<PAGE>
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                             Form 10-K

                  Securities and Exchange Commission

                        Washington, D.C. 20549



(Mark One)
[ X ]  Annual Report Pursuant to Section 13 or 15(d) of the
       Securities Exchange Act of 1934

             For the fiscal year ended DECEMBER 31, 1995


                              OR


[   ]  Transition Report pursuant to Section 13 or 15(d) of the
       Securities Exchange Act of 1934

     For the transition period from ____________ to ____________



                   Commission file number 1-1217


             Consolidated Edison Company of New York, Inc.
       (Exact name of registrant as specified in its charter)


        New York                         13-5009340
(State of Incorporation)     (I.R.S. Employer Identification No.)


4 Irving Place, New York, New York           10003
(Address of principal executive offices)   (Zip Code)


           Registrant's telephone number: (212) 460-4600


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<PAGE>                        - 2 -

Securities Registered Pursuant to Section 12(b) of the Act:

                                            Name of each exchange
Title of each class                          on which registered

Consolidated Edison Company of New York, Inc.
   $5 Cumulative Preferred Stock, without par value   New York
                                                      Stock
                                                      Exchange
   Cumulative Preferred Stock, 4.65%                  New York
   Series C ($100 par value)                          Stock
                                                      Exchange
   Cumulative Preference Stock, 6%                    New York
   Convertible Series B ($100 par value)              Stock
                                                      Exchange
   Common Stock ($2.50 par value)           New York, Chicago and
                                                   Pacific Stock
                                                   Exchanges
   7 3/4% Quarterly Income Capital Securities         New York
   (Series A Subordinated Deferrable                  Stock
   Interest Debentures)                               Exchange

Kings County Electric Light and Power Company,
   Purchase Money, 6%, 99 Years Gold Bonds,           New York
   due October 1, 1997                                Stock
   (non-callable)                                     Exchange

Securities Registered Pursuant to Section 12(g) of the Act:

Title of each class

Consolidated Edison Company of New York, Inc.
Cumulative Preferred Stock ($100 par value):
     4.65% Series D
     5-3/4% Series E
     6.20% Series F

     Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months,
and (2) has been subject to such filing requirements for the past
90 days.
                                 Yes    X                 No      
 
     Indicate by check mark if the disclosure of delinquent
filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrant's
knowledge, in the definitive proxy statement incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  [   ]
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<PAGE>                        - 3 -

     The aggregate market value of the voting stock held by
non-affiliates of the registrant, as of January 31, 1996, was 
$8,077,210,542.  Excluded from this figure is $2,315,554
representing the market value of 68,609 shares of Common Stock
held by the registrant's Trustees (directors).  The registrant's
Trustees are the only stockholders of the registrant, known to
the registrant, who might be deemed "affiliates" of the
registrant.

     As of February 29, 1996, the registrant had outstanding
234,966,127 shares of Common Stock.


                   Documents Incorporated By Reference

     Portions of the registrant's Proxy Statement for its 1996
Annual Meeting of Stockholders, to be filed with the Commission
pursuant to Regulation 14A not later than 120 days after December
31, 1995, the close of the registrant's fiscal year, are incorpo-
rated in Part III of this report.


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<PAGE>                        - 4 -

                        TABLE OF CONTENTS


                                                            Page

PART I

ITEM 1.  Business . . . . . . . . . . . . . . . . . . . .      5
ITEM 2.  Properties . . . . . . . . . . . . . . . . . . .     27
ITEM 3.  Legal Proceedings  . . . . . . . . . . . . . . .     30
ITEM 4.  Submission of Matters to a Vote of 
         Security Holders . . . . . . . . . . . . . . . .   None
Executive Officers of the Registrant  . . . . . . . . . .     41


PART II

ITEM 5.  Market for the Registrant's Common Equity 
         and Related Stockholder Matters  . . . . . . . .     49
ITEM 6.  Selected Financial Data  . . . . . . . . . . . .     49
ITEM 7.  Management's Discussion and Analysis
         of Financial Condition and Results of 
         Operations   . . . . . . . . . . . . . . . . . .     50
ITEM 8.  Financial Statements and Supplementary Data. . .     69
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  . . . . . . . . . . . . . . . . . .     *
ITEM 11.  Executive Compensation  . . . . . . . . . . . .     *
ITEM 12.  Security Ownership of Certain Beneficial 
          Owners and Management . . . . . . . . . . . . .     *
ITEM 13.  Certain Relationships and Related 
          Transactions  . . . . . . . . . . . . . . . . .     *


PART IV

ITEM 14.  Exhibits, Financial Statement Schedules 
          and Reports on Form 8-K . . . . . . . . . . . .    104


SIGNATURES  . . . . . . . . . . . . . . . . . . . . . . .    116
___________________
*Incorporated by reference from the Company's definitive proxy
statement for its Annual Meeting of Stockholders to be held on
May 20, 1996.
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<PAGE>                        - 5 -

                               PART I


ITEM 1. BUSINESS

Contents of Item 1                                          Page

       THE COMPANY . . . . . . . . . . . . . . . . . . . . .   5
       INDUSTRY SEGMENTS . . . . . . . . . . . . . . . . . .   5
       ELECTRIC OPERATIONS . . . . . . . . . . . . . . . . .   6
       GAS OPERATIONS  . . . . . . . . . . . . . . . . . . .   9
       STEAM OPERATIONS  . . . . . . . . . . . . . . . . . .  11
       CAPITAL REQUIREMENTS AND FINANCING  . . . . . . . . .  12
       FUEL SUPPLY   . . . . . . . . . . . . . . . . . . . .  12
       REGULATION AND RATES  . . . . . . . . . . . . . . . .  15
       COMPETITION . . . . . . . . . . . . . . . . . . . . .  18
       ENVIRONMENTAL MATTERS AND 
        RELATED LEGAL PROCEEDINGS  . . . . . . . . . . . . .  18
       GENERAL . . . . . . . . . . . . . . . . . . . . . . .  22
       EMPLOYEES . . . . . . . . . . . . . . . . . . . . . .  22
       RESEARCH AND DEVELOPMENT  . . . . . . . . . . . . . .  22
       OPERATING STATISTICS  . . . . . . . . . . . . . . . .  23
       FIVE-YEAR FORECAST  . . . . . . . . . . . . . . . . .  25


THE COMPANY

     Consolidated Edison Company of New York, Inc. (the Company),
incorporated in New York State in 1884, supplies electric service
in all of New York City (except part of Queens) and most of
Westchester County, an approximately 660 square mile service area
with a population of more than 8 million.  It also supplies gas
in Manhattan, The Bronx and parts of Queens and Westchester, and
steam in part of Manhattan.  Most governmental customers within
the Company's service territory receive electric service from the
New York Power Authority (NYPA) through the Company's facilities.

     In 1995, electric, gas and steam operating revenues were
82.5 percent, 12.4 percent and 5.1 percent, respectively, of the
Company's operating revenues.

INDUSTRY SEGMENTS

     For information on operating revenues, expenses and income
for the years ended December 31, 1995, 1994 and 1993, and assets
at those dates, relating to the Company's electric, gas and steam
operations, see Note I to the financial statements in Item 8.
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ELECTRIC OPERATIONS

     ELECTRIC SALES.  Electric operating revenues were $5.4
billion in 1995 or 82.5 percent of total Company operating
revenues.  The percentages were 80.6 and 81.9, respectively, in
the two preceding years.  Electricity sales in the Company's
service area in 1995, including usage by customers served by NYPA
and the New York City and Westchester County municipal electric
agencies, but excluding off-system sales, increased 0.7 percent
from 1994, after increasing 2.0 percent and 3.3 percent,
respectively, in the two preceding years.  After adjusting for
variations, principally weather and billing days, electricity
sales volume increased 1.2 percent in 1995, 1.5 percent in 1994
and 1.0 percent in 1993.  Weather-adjusted sales represent the
Company's estimate of the sales that would have been made if
historical average weather conditions had occurred.

    In 1995, 79.9 percent of the electricity delivered in the
Company's service area was sold by the Company to its customers,
and the balance was delivered to customers of NYPA and municipal
electric agencies.  Of the Company's sales, 29.3 percent was to
residential customers, 66.6 percent was to commercial customers,
2.4 percent was to industrial customers and the balance was to
railroads and public authorities.

    For further information about amounts of electric energy
sold, see "Operating Statistics", below.  For a forecast of
electric energy sales, see "Five-Year Forecast", below.

     ELECTRIC SUPPLY.  The Company either generates the electric
energy it sells, purchases the energy from other utilities or
independent power producers (IPPs) pursuant to long-term firm
power contracts or purchases non-firm economy energy.

     The sources of electric energy generated and purchased
during the years 1991-1995 are shown below: 

                            1991    1992    1993    1994    1995
Generated:
  Fossil-Fueled . . . . .  51.4%   42.3%   35.5%   30.9%   30.1%*
  Nuclear (Indian Point 2)  9.8%   20.4%   14.8%   18.4%   10.8%
    Total Generated . . .  61.2%   62.7%   50.3%   49.3%   40.9%
Firm Purchases:
  NYPA  . . . . . . . . .   8.9%    4.8%    6.0%    1.3%    1.3%
  Hydro-Quebec . . . . .    1.9%    2.9%    4.3%    4.8%    5.8%
  IPPs  . . . . . . . . .   1.0%    8.9%   11.9%   12.9%   29.9%
Other Purchases . . . . .  27.0%   20.7%   27.5%   31.7%   22.1%*
Generated & Purchased . .  100%    100%    100%    100%    100%
_____
*Reflects amounts relating to electricity generated for others. 
See "Gas Conversions" and "Operating Statistics", below.
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<PAGE>                         - 7 -

     For further information about amounts of electric energy
generated and purchased, see "Operating Statistics", below.  For
information about the Company's generating facilities, see
Electric Facilities - Generating Facilities" in Item 2.  For
information about the Company's purchases of electric energy, see
"NYPA", "Hydro-Quebec", "Independent Power Producers", "New York
Power Pool" and "Gas Conversions", below.

     ELECTRIC PEAK LOAD AND CAPACITY.  The electric peak load in
the Company's service area occurs during the summer air
conditioning season.  The 1995 one-hour peak load in the
Company's service area (which occurred on August 2, 1995) was
10,805 thousand kilowatts (MW) -- a record for the service area,
exceeding the previous record peak of 10,752 MW (which occurred
on July 23, 1991).  The 1995 peak load included an estimated
9,216 MW for the Company's customers and 1,589 MW for NYPA's
customers and municipal electric agency customers.  It is
estimated that the 1995 peak load was reduced by 28 MW due to
curtailable load reduction.  The 1995 peak, if adjusted to
historical design weather conditions, would have been 10,850 MW,
150 MW higher than the peak in 1994 when similarly adjusted. 
"Design weather" for the electric system is a standard to which
the actual peak load is adjusted for evaluation.

     The capacity resources available to the Company's service
area at the time of the system peak in the summer of 1995
totalled (before outages) 14,115 MW, of which 10,489 MW
represented net available generating capacity (including the
capacity of NYPA's Poletti and Indian Point 3 units) and 3,626 MW
represented net firm purchases by the Company and NYPA.

     For a forecast of peak load and capacity, see "Five-Year
Forecast", below.  For information about the Company's
generating, transmission and distribution facilities, see
"Electric Facilities" in Item 2.  For information about the
Company's plans to meet its requirements for electric capacity,
see "Liquidity and Capital Resources - Electric Capacity
Resources" in Item 7.

     NYPA.  NYPA supplies its customers in the Company's service
area with electricity from its Poletti fossil-fueled unit in
Queens, New York, its Indian Point 3 nuclear unit in Westchester
County and other NYPA sources.  Electricity is delivered to these
NYPA customers through the Company's transmission and
distribution facilities, and NYPA pays a delivery charge to the
Company.  NYPA is contractually obligated to the Company to
provide the capacity needed to meet the present and future
electricity requirements of its customers, except that upon 17
years' prior notice to the Company, NYPA may elect not to provide
for future growth of its customers' requirements.  NYPA's Indian
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<PAGE>                         - 8 -

Point 3 unit, after being out of service throughout 1994, was
returned to service on June 29, 1995.  It remained in service
until September 14, 1995, and did not return for the remainder of
the year.  During these outage periods, NYPA met its capacity
requirements from other sources, including firm purchases.

     The Company purchases portions of the output of Poletti and
Indian Point 3 on a firm basis.  The Company also purchases firm
capacity from NYPA's Blenheim-Gilboa pumped-storage generating
facility in upstate New York.  The Company and NYPA also sell to
each other energy on a non-firm basis.

     HYDRO-QUEBEC.  The Company has an agreement with NYPA to
purchase, through a contract between NYPA and Hydro-Quebec (a
government-owned Canadian electric utility), 780 MW of capacity
and associated kilowatt-hours of energy each year during the
months of April through October until October 31, 1998.  The
amount and price of a "basic amount" of energy the Company is
entitled to purchase each year are subject to negotiation with
Hydro-Quebec and approval by the National Energy Board of Canada,
a Canadian regulatory agency.  However, the capacity commitment
is firm and the Company may draw upon the capacity in accordance
with the contract even if the energy received by the Company
exceeds the basic amount, provided the Company returns the excess
energy to Hydro-Quebec during the following November-through-
March period.  Subject to regulatory approvals, this contract has
been extended to cover purchases by the Company of 400 MW of
power during the April through October periods of 1999 through
2003.

     INDEPENDENT POWER PRODUCERS.  Federal and state regulations
encourage competition in the market for generation of electric
power.  These laws generally require electric utilities to
purchase electric power from and sell electric power to
qualifying IPPs.  The Federal Energy Regulatory Commission (FERC)
has issued rules requiring utilities to purchase electricity from
all qualifying facilities at a price equal to the purchasing
utility's "avoided cost."  In addition, the Energy Policy Act of
1992 broadened the FERC's authority to require electric utilities
to provide others with access to their transmission systems and
reduced regulation of certain IPPs.

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<PAGE>                         - 9 -

     For information about the Company's contracts with IPPs, see
"Liquidity and Capital Resources - Electric Capacity Resources
and Competition" in Item 7 and Note G to the financial statements
in Item 8.

     NEW YORK POWER POOL.  The Company and the other major
electric utilities in New York State, including NYPA, are members
of the New York Power Pool. The primary purpose of the Power Pool
is to coordinate planning and operations so as to better assure
the reliability of the State's interconnected electric systems.

     As a member of the Power Pool, the Company is required to
maintain its capacity resources (net generating capacity and net
firm purchases) at a minimum reserve margin of 18% above its peak
load, and to pay penalties if it fails to maintain the required
level.  The Company met the reserve requirement in 1995 and
expects to meet it in 1996.  See "Five-Year Forecast", below.

     MUNICIPAL ELECTRIC AGENCIES.  Westchester County and New
York City maintain municipal electric agencies to purchase
electric energy, including hydroelectric energy from NYPA.  The
Company has entered into agreements with the County and City
agencies whereby the Company is delivering interruptible
hydroelectric energy from NYPA's Niagara and St. Lawrence
projects to electric customers designated by the agencies.  These
agreements may be terminated by either party upon either one
year's prior notice or, in certain circumstances, upon 10 days'
notice.  A similar agreement, covering energy from NYPA's
Fitzpatrick nuclear plant, provides for termination in 2010.  For
information on the amount of energy delivered, see "Operating
Statistics", below.

     GAS CONVERSIONS.  In 1995, the Company, for a fee, generated
3,159,047 MWhrs of electric energy for others using as fuel gas
that they provided.  This amounted to 7.0% of the electric energy
generated and purchased by the Company in 1995.  The Company
subsequently purchased 2,666,837 MWhrs of such electric energy
for sale to its own customers.


GAS OPERATIONS

     GAS SALES.  Gas operating revenues in 1995 were $813.4
million or 12.4 percent of total Company operating revenues.  
The percentages were 14.0 and 12.9, respectively, in the two
preceding years.  Gas sales volume to firm customers decreased
2.8 percent in 1995 from the 1994 level.  After adjusting for
variations, principally weather, firm gas sales volume to these
customers increased 0.1 percent. Including sales to interruptible
and off-system customers, actual sales volume increased 0.9
percent in 1995.
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<PAGE>                         - 10 -

     Natural gas is delivered by pipeline to the Company and is
distributed to customers through the Company's system of
distribution mains and services.  For information about the
Company's gas facilities, see "Gas Facilities" in Item 2.

     Regulatory changes, which have resulted in the unbundling of
services in the natural gas industry, enable users of gas to
purchase gas directly from suppliers other than their local
utility and arrange for (and pay for) its transportation by the
appropriate pipeline companies and local utilities.  See
"Regulation and Rates - Generic Proceedings", below.

     In 1995, 78 large-volume customers (at least 5,000
dekatherms per annum) in the Company's service territory had
contracts enabling them to purchase gas directly from other
suppliers.  Each month 75% or more of these customers purchased
their gas for the month from the Company.  Beginning in 1996,
pending PSC approval, all gas customers, either individually (at
least 3,500 dekatherms per annum) or by aggregating their demand
with other customers (at least 5,000 dekatherms per annum), will
be eligible to purchase gas directly from suppliers other than
the Company.   Regardless of whether the Company's gas customers
purchase gas from the Company or other suppliers, the customers
pay the Company for transporting the gas.

     During 1995, the Company entered into off-system sales
transactions such as releases of pipeline capacity and bundled
sales of gas and ancillary services.

    For information on the quantities of gas sold, transported
for others and used by the Company as boiler fuel to generate
electricity and steam, see "Operating Statistics" and "Fuel
Supply", below.

     In 1993, the Company established an unregulated subsidiary
which markets gas and related services.  In 1995, the Company
petitioned the PSC to eliminate its territorial restriction which
prohibits the subsidiary from marketing gas within the Company's
gas service area.

     GAS REQUIREMENTS.  Demand for gas in the Company's service
area peaks during the winter heating season.  The design criteria
for the Company's gas system assume severe weather conditions
that have not occurred in the Company's service area since 1934. 
Under these criteria, the Company estimates that the requirements
to supply its firm gas customers, together with the minimum
amount essential for its electric and steam systems, would amount
to 72,900 thousand dekatherms (mdth) of gas during the 1995/96
winter heating season and that gas available to the Company would
amount to 91,900 mdth.  For the 1996/97 winter, the Company
estimates that the requirements would amount to approximately 
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<PAGE>                         - 11 -

73,100 mdth and that the gas available to the Company would
amount to approximately 91,900 mdth.  As of March 20, 1996, the 
1995/96 winter peak day sendout to the Company's customers was
739 mdth, which occurred on January 6, 1996.  The Company
estimates that, under the design criteria, the peak day
requirements for firm customers during the 1996/97 winter season
would amount to approximately 865 mdth and expects that it would
have sufficient gas available to meet these requirements.

     GAS SUPPLY.  The Company has contracts for the purchase of
firm transportation and storage services with seven interstate
pipeline companies.  The Company also has contracts with
seventeen pipeline and non-pipeline suppliers for the firm
purchase of natural gas.  The Company also has interruptible gas
purchase contracts with numerous suppliers and interruptible gas
transportation contracts with interstate pipelines.  Based on its
current projections of demand and prices for gas and oil, the
Company expects for at least the next several years to be able to
supply its firm gas customers' requirements, maintain an adequate
inventory of storage gas and meet most of the requirements of its
large-volume interruptible customers.  Gas Operations also
purchases gas for the Company's electric and steam generating
stations.

STEAM OPERATIONS

     STEAM SALES.  The Company sells steam in Manhattan south of
96th Street, mostly to large office buildings, apartment houses
and hospitals.  In 1995, steam operating revenues were $334.1
million or 5.1 percent of total Company operating revenues.  The
percentages were 5.4 and 5.2, respectively, in the two preceding
years.  Steam sales volume decreased 4.1 percent in 1995 from the
1994 level.  After adjusting for variations, principally weather,
steam sales decreased 1.9 percent.

     STEAM SUPPLY.  55.7 percent of the steam sold by the Company
in 1995 was produced in the Company's electric generating
stations, where it is first used to generate electricity.  For
information about the Company's steam facilities, see "Steam
Facilities" in Item 2.

     STEAM PEAK LOAD AND CAPABILITY.  Demand for steam in the
Company's service area peaks during the winter heating season. 
The one-hour peak load during the winter of 1995/96 (through
March 20, 1996) occurred on February 5, 1996 when the load
reached 11.0 million pounds.  The Company estimates that for the
winter of 1996/97 the peak demand of its steam customers would be
approximately 12.4 million pounds per hour under design criteria,
which assume severe weather.

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<PAGE>                         - 12 -

     On December 31, 1995, the steam system had the capability of
delivering about 13.2 million pounds of steam per hour.  This
figure does not reflect the unavailability or reduced capacity of
generating facilities resulting from repair or maintenance.  The
Company estimates that, on a comparable basis, the system will
have the capability to deliver approximately 13.3 million pounds
of steam per hour in the 1996/97 winter.

CAPITAL REQUIREMENTS AND FINANCING

     For information about the Company's capital requirements and
financing, the refunding of certain securities and the Company's
securities ratings, see "Liquidity and Capital Resources" in Item
7.

     Securities ratings assigned by rating organizations are
expressions of opinion and are not recommendations to buy, sell
or hold securities.  A securities rating is subject to revision
or withdrawal at any time by the assigning rating organization. 
Each rating should be evaluated independently of any other
rating.

     For a forecast of certain operating and financial data, see
"Five-Year Forecast", below.

FUEL SUPPLY

     GENERAL.  In 1995, 23.4 percent of the electricity supplied
to the Company's customers was obtained by the Company through
economy purchases of energy produced from a variety of fuels.  Of
the remaining 76.6 percent, which was either obtained through
firm purchases of energy, generated by the Company for its
customers, or generated by the Company for others from their fuel
and subsequently purchased by the Company (see "Electric
Operations", above), oil was used to generate 5.1 percent of the
electricity, natural gas 54.0 percent, nuclear power 10.8
percent, hydroelectric power 5.8 percent, and refuse 0.9 percent. 
The fuel used to produce steam during 1995 was 68.5 percent oil
and 31.5 percent natural gas.

     A comparison of the cost, in cents per million Btu, of fuel
used by the Company to generate electricity and steam during the
years 1991-1995 is shown below:

                            1991   1992   1993   1994   1995
Residual Oil . . . . .       355    345    348    349    348
Distillate Oil . . . .       491    501    499    467    399
Natural Gas  . . . . .       288    285    286    255    197
Nuclear  . . . . . . .        50     43     37     42     51
Weighted Average . . .       281    232    229    215    205

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<PAGE>                         - 13 -

     The Company is prohibited from using fuels that do not
conform to the requirements of the New York State air pollution
control code and, in the case of its in-City plants, the New York
City air pollution control code.  In the City, the Company is not
permitted to burn coal or to burn residual fuel oil having a
sulfur content of more than 0.3 percent.

     RESIDUAL OIL.  Based on anticipated consumption rates, the
Company has an adequate supply of residual fuel oil for its
generating stations and the Company's shares of generating
capacity at the Roseton and Bowline Point stations jointly-owned
by the Company and other utilities.  See "Electric Facilities" in
Item 2.  Oil consumption rates vary widely from month to month. 
The oil burned at Company facilities in 1995, including the
Company's shares of generating capacity at Roseton and Bowline
Point, totaled 9.6 million barrels.  The Company has contracts
for oil supply that have staggered termination dates and has
options for additional oil supply sufficient to cover all of its
expected requirements for residual oil through September 1996. 
The Company anticipates covering the balance of its 1996
requirements through new contracts, exercise of existing contract
options and purchases on the spot market.

     NATURAL GAS.  During 1995, the Company burned approximately
119,500 mdth of gas for the production of electricity and steam,
including 18,900 mdth attributable to the Company's share of
generating capacity at the Roseton and Bowline Point stations and
31,700 mdth of gas provided by others.  See "Electric Operations
- Gas Conversions", above.  The Company expects to continue to
have substantial amounts of gas available in 1996 for the
production of electricity and steam for its customers.

     DISTILLATE OIL.  The Company's estimated 1996 requirements
for distillate oil for gas turbine fuel are about 200,000
barrels.  The Company expects to be able to satisfy these
requirements through purchases on the spot market.

     COAL.  The Company does not burn coal.  In 1983, the New
York State Department of Environmental Conservation (DEC) ruled
on an application by the Company for permission to convert three
electric generating units, Ravenswood 3 in Queens and Arthur Kill
2 and 3 on Staten Island, to coal-burning.  The DEC ruled that
the Company would be permitted to burn coal at each location only
if flue gas desulfurization (FGD) systems were installed.  The
Company's studies showed that it would not be economical to
pursue coal conversion with FGD systems.  However, the Company
has installed most of the necessary facilities (without FGD
systems) at Ravenswood 3 and Arthur Kill 3 to provide for
coal-burning in emergency circumstances such as an oil supply 
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<PAGE>                         - 14 -

interruption.  Even in such an emergency, a special permit, or
waiver of existing restrictions, would be required to allow the
Company to burn coal at these units.

     NUCLEAR FUEL.  The nuclear fuel cycle for power plants like
Indian Point 2 consists of (1) mining and milling of uranium ore,
(2) chemically converting the uranium in preparation for
enrichment, (3) enriching the uranium, (4) fabricating the
enriched uranium into fuel assemblies, (5) using the fuel
assemblies in the generating station and (6) storing the spent
fuel.

     Contracts for uranium and conversion are in the process of
being negotiated.  The uranium supply provided under these
contracts, together with the supply the Company has already
purchased, will be sufficient for the planned 1997 refueling of
Indian Point 2.  Arrangements are expected to be completed in
1996 for the additional uranium supply required for the expected
1999 refueling of Indian Point 2.  The Company has a contract
covering its expected requirements for fuel fabrication services
through 2001.  A new contract for fuel fabrication services, is
in the process of being negotiated.  This contract would cover
all of the Company's requirements for fuel fabrication services
through the expiration of Indian Point 2's operating license in
2013.  The Company has contracts covering most of its
requirements for uranium enrichment services through 2013. 

     Under the Energy Policy Act of 1992, the DOE is to collect a
special annual assessment, for a period of 15 years, from
utilities that have purchased enriched uranium from the DOE.  The
assessments are to be used to pay a portion of the costs to
decontaminate and decommission DOE's gaseous diffusion facilities
used to enrich uranium for commercial and defense purposes.  The
Company has paid assessments attributable to Indian Point Units 1
and 2 for 1993 through 1996.  The 1996 assessment was
approximately $2.6 million.  Future amounts are subject to review
and adjustment for inflation.  The Company's liability at
December 31, 1995 for future installments of this assessment is
$28.9 million, of which $26.2 million is classified as non-
current.  The Company is recovering these costs through its
electric fuel adjustment clause.

     Under normal operating conditions, scheduled refueling and
maintenance outages are generally required for Indian Point 2
after each cycle of approximately 22 months of operation.  A
scheduled refueling and maintenance outage commenced on February
4, 1995 and ended on June 6, 1995.  Mid-cycle inspection and
maintenance outages may also be required from time to time.

     See "Nuclear Decommissioning" in Note A to the financial
statements in Item 8.
<PAGE>
<PAGE>                         - 15 -

     The Company is one of twelve utilities participating in
plans to license and build an interim, commercial, spent nuclear
fuel storage facility by 2002 on lands under the jurisdiction of
the Mescalero Apache Tribe in New Mexico.  It is expected that
each participating utility will contribute approximately $1
million for engineering, licensing and legal studies for the
preparation of a license submittal to the Nuclear Regulatory
Commission by the first quarter of 1997.  Thereafter, each
participating utility will have an opportunity to decide whether
or not to continue its participation in this project.  See
"Liquidity and Capital Resources -- Nuclear Fuel Disposal" in
Item 7.

     The Company has arranged for the disposal of low-level
radioactive wastes (LLRW) generated at Indian Point 1 and 2 at a
licensed disposal facility near Barnwell, South Carolina which is
currently accepting LLRW for permanent disposal.  Under a 1985
Federal law, by January 1996 New York State was to provide for
permanent disposal of the Company's LLRW.  The Company will be
capable of providing such on-site storage of LLRW as may be
required until New York State establishes a storage facility or
adopts some other LLRW management method.

REGULATION AND RATES

     GENERAL.  The New York State Public Service Commission (PSC)
regulates, among other things, the Company's electric, gas and
steam rates, the siting of its transmission lines and the
issuance of its securities.

     Certain activities of the Company are subject to the
jurisdiction of the Federal Energy Regulatory Commission (FERC). 
The Nuclear Regulatory Commission (NRC) regulates the Company's
nuclear units.  In addition, various matters relating to the
construction and operation of the Company's facilities are
subject to regulation by other governmental agencies.

     ELECTRIC, GAS and STEAM RATES.  The Company's rates are
among the highest in the country.  For additional information
about the Company's rates, see "Liquidity and Capital Resources -
1992 Electric Rate Agreement, 1995 Electric Rate Agreement and
Gas and Steam Rate Agreements" in Item 7.

<PAGE>
<PAGE>                         - 16 -

     In 1994, a controversy arose over the rates the Company
charges to religious organizations.  State law requires electric
and gas utilities to charge religious organizations rates that do
not exceed those charged to residential customers.  Due mainly to
the complexity of the Company's rates, a significant number of
religious institutions, for the most part small store-front type
accounts, had been served under generally higher commercial
rates.  In December 1994, the Company and the Attorney General
executed a settlement under which the Company admitted no
wrongdoing but agreed to provide refunds amounting to $5 to $6
million to affected religious organizations and transfer affected
customers to the appropriate rates.  In a related matter, seven
customers, each stating that it is a church, have sued the
Company in Federal court.  Each plaintiff claims that it has
operated as a religious organization and has been charged
commercial rates for electric service.  The plaintiffs are
seeking $500 million for the class members in this purported
class action.  The Company is opposing plaintiffs' motion for
class certification and the Company has made a motion for summary
judgment.

     GENERIC PROCEEDINGS.  See "Liquidity and Capital Resources -
Competition - PSC Proceeding" in Item 7.  A PSC order in this
proceeding is expected during the second quarter of 1996.

     In 1991, the PSC initiated a proceeding to review the
financial policies it uses to set utility rates.  In May 1993,
the Company agreed with the PSC staff, the other New York State
electric and gas utilities and intervenors that the PSC should
establish an "A" bond rating as the appropriate financial
integrity target in order to give utilities needed access to
financial markets on reasonable terms.  Under this agreement, no
action would be taken to reduce the rating of utilities above the
"A" level unless the PSC found that the higher rating was
inconsistent with the public interest.  In June 1993, the
utilities, the PSC staff and one intervenor in this proceeding
agreed to a new method of calculating the cost of common equity
in rate cases.  The new method is less volatile because it is
less sensitive to changes in interest rates than the method the
PSC traditionally has used.  In July 1994, the Administrative Law
Judges issued a recommended decision.  The judges generally
accepted the parties' resolution of financial integrity issues,
but rejected the agreement on the method of calculating the cost
of common equity.  Instead, the judges recommended their own
method, which is more sensitive to changes in interest rates than
the method agreed to with the PSC staff and the intervenor.  A
PSC decision, which was expected in 1995, has not yet been
issued.

<PAGE>
<PAGE>                         - 17 -

     For several years the PSC has required utilities to favor
demand side resources in evaluating the cost-effectiveness of
such resources by deeming their cost to be reduced by savings
from avoiding adverse environmental impacts ("externalities"). 
Currently, the required reduction is 1.6 cents per kilowatt-hour. 
In 1992, the PSC instituted a proceeding to reexamine the
appropriate value for externalities.  Consideration is being
given to the application of externalities to supply side
resources and the use of environmental (as opposed to economic)
dispatch.  In 1995, the Administrative Law Judge recommended that
the PSC discontinue the use of externalities in demand-side
management programs and reject proposals to expand the use of
externalities to supply-side resources.  The PSC has not yet
issued a decision, but an adverse decision could significantly
increase electric rates.  In a separate proceeding, the Company,
together with other members of the New York Power Pool, entered
into a settlement agreement under which the utilities would
procure about 300-400 MW of renewable resources provided that
these resources could be obtained at an acceptable price.  The
settlement agreement was "approved" by the PSC except that the
PSC expanded the Company's obligations to purchase electric
capacity.  As a result of the PSC's actions, the Company and
other NYPP members withdrew from the settlement agreement because
they believe that the PSC's substantial modification of the
agreement constitutes rejection of the agreement.  In May 1995,
the utilities filed a motion with the PSC to terminate the
proceeding, to vacate the order approving the settlement, and to
declare the settlement void.  The utilities also filed a state
court appeal, which has been stayed pending a PSC decision on the
utilities' motion.

     In late 1993, the PSC instituted a proceeding to examine the
impact of the emerging competitive gas market on gas utility
rates and services.  In particular, the PSC wanted to explore the
impact of "unbundling" of sales and transportation services by
interstate pipeline companies pursuant to FERC Order 636.  In
December 1994, the PSC issued an order establishing regulatory
policies and guidelines for gas utilities regarding the pricing
and provision of bundled and unbundled sales and transportation
services.  An August 1995 order required utilities to reflect
these policies in a compliance filing.  The Company has made the
required compliance filing and has proposed a performance-based
gas purchase mechanism to be effective April 1, 1996. The
Commission has announced that it is readying an order that
requires the Company to implement its filing with Commission-
imposed modifications within 30 days of the order's issuance.

<PAGE>
<PAGE>                         - 18 -

     STATE ENERGY PLAN.  In October 1994, the New York State
Energy Planning Board, released its most recent State Energy
Plan.  The Plan is designed to provide "an intelligent framework
for evaluating the proper course for energy policy, environmental
protection and economic development. . . to assure that New
Yorkers will have a safe, affordable and reliable supply of
energy that will promote future economic growth and protect our
environment."  Under New York State law, any energy-related
decisions of State agencies must be reasonably consistent with
the Plan.

COMPETITION

     For information concerning competition in the electricity
and gas business, see "Liquidity and Capital Resources - Electric
Capacity Resources and Competition" in Item 7 and "Gas Operations
- Gas Sales" above.

     The PSC has issued rules requiring competitive bidding to be
the primary means by which additional electric capacity and
energy is obtained by utilities, although the PSC has indicated
that utilities should pursue other alternatives when justified.

ENVIRONMENTAL MATTERS AND RELATED LEGAL PROCEEDINGS

    GENERAL.  During 1995, the Company's capital expenditures for
environmental protection facilities and related studies were
approximately $26 million. The Company estimates that such
expenditures will amount to approximately $42 million in 1996 and
$40 million in 1997.  These amounts include capital expenditures
in 1996 and 1997 required to comply with the consent decree
discussed under "Environmental Matters - DEC Settlement" in Note
F to the financial statements in Item 8.

    INDIAN POINT.  The Company believes that a serious accident
at its Indian Point 2 nuclear unit is extremely unlikely, but
despite substantial insurance coverage, the losses to the Company
in the event of a serious accident could materially adversely
affect the Company's financial position and results of
operations. For information about Indian Point 2 and the
Company's retired Indian Point 1 nuclear unit, see "Electric
Operations" and "Fuel Supply - Nuclear Fuel" above, "Cooling
Towers" below, "Electric Facilities - Generating Facilities" in
Item 2, "Liquidity and Capital Resources - Capital Requirements"
in Item 7 and Notes A and F to the financial statements in Item
8.

<PAGE>
<PAGE>                         - 19 -

     SUPERFUND.  The Federal Comprehensive Environmental
Response, Compensation and Liability Act of 1980 (Superfund) by
its terms imposes joint and several strict liability, regardless
of fault, upon generators of hazardous substances for resulting
removal and remedial costs and environmental damages.

    In the course of the Company's operations, materials are
generated that are deemed to be hazardous substances under
Superfund.  These materials include asbestos and dielectric
fluids containing polychlorinated biphenyls (PCBs).  Other
hazardous substances may be generated in the Company's operations
or may be present at Company locations.  Also, other hazardous
substances may have been generated at the manufactured gas plants
which the Company and its predecessor companies used to operate.

    For additional information about Superfund, see "Superfund"
in Item 3 and "Environmental Matters - Superfund Claims" in Note
F to the financial statements in Item 8.

    ASBESTOS.  Asbestos is present in numerous Company
facilities.  In 1989, a Company steam main exploded in the
Gramercy Park area of Manhattan, causing asbestos contamination
of nearby buildings and requiring a major cleanup.  Most of the
costs were covered by insurance.  See "Gramercy Park" in Item 3.

    For additional information about asbestos, see "Environmental
Matters - Asbestos Claims" in Note F to the financial statements
in Item 8 and "Asbestos Litigation" in Item 3.

     TOXIC SUBSTANCES CONTROL ACT.  Virtually all electric
utilities, including the Company, own equipment containing PCBs. 
PCBs are regulated under the Federal Toxic Substances Control Act
of 1976.  The Company has reduced substantially the amount of
PCBs in electrical equipment it uses, including transformers
located in or near public buildings.

     For information about a claim under the Toxic Substances
Control Act, see "Toxic Substances Control Act" in Item 3.

     AIR QUALITY.  For information about the Federal Clean Air
Act amendments of 1990, see "Liquidity and Capital Resources -
Clean Air Act Amendments" in Item 7.

     The flue gases from oil combustion furnaces, including the
Company's generating stations as well as home heating furnaces,
contain microscopic particles of ash and soot.  Some chemical
constituents of these particles have been designated as
"Hazardous Air Pollutants" under the Clean Air Act Amendments of
1990.  Utility boilers are exempt from regulation as sources of 
<PAGE>
<PAGE>                         - 20 -

hazardous air pollutants until the United States Environmental
Protection Agency (EPA) completes a study of the hazards to
public health reasonably anticipated to occur as a result of 
emissions by electric generating units.  In 1995, the EPA issued
a draft report regarding the study.  The draft report contains no
conclusions concerning the need for control of hazardous air
pollutants from utility facilities.

     The New York State Department of Environmental Conservation
(DEC) in March 1991 issued a notice of intent to prepare a draft
environmental impact statement (DEIS) concerning a DEC draft of
regulations that would establish standards of performance,
effective beginning in the year 2000, for steam electric
generating units that are operated beyond their "useful design
life."  The DEC draft regulations define "useful design life" as
45 years from the date of initial operation.  All of the
Company's steam electric generating units in New York City will
have reached that point by 2014.  The draft regulations would
impose operating efficiency requirements (heat rates) that many
of these units may not be able to meet, and stringent nitrogen
oxides and particulate matter emissions limitations.  The DEC has
not yet issued the DEIS.

     The DEIS process affords the Company and other interested
parties the opportunity to submit comments and suggest changes to
the draft regulations.  Upon completion of the DEIS, the DEC may
propose regulations for adoption.  If the DEC proposes
regulations in their current draft form and they are adopted, the
regulations could require the retirement of many of the Company's
in-City electric generating units earlier than planned, starting
in the year 2000.  The Company and the New York Power Pool will
oppose adoption of any regulations that would impose unreasonable
standards of performance on electric generating units or require
the premature retirement of such units.  The Company is unable to
predict the final form of the regulations or whether the DEC will
ultimately adopt such regulations.

     The New York City air pollution control code contains
limitations on the allowable sulfur content of fuels and on
emissions of sulfur dioxide, particulate matter, oxides of
nitrogen and various trace elements.  Certain provisions of the
code, specifically those pertaining to standards for emissions of
nitrogen oxides, may be impracticable to meet at some of the
Company's generating stations located in New York City unless
variances or other relief from such provisions are granted.
<PAGE>
<PAGE>                         - 21 -

     COOLING TOWERS.  The Federal Clean Water Act provides for 
effluent limitations, to be implemented by a permit system, to
regulate the discharge of pollutants, including heat, into United
States waters.  In 1981, the Company entered into a settlement
with the EPA and others that relieved the Company for at least 10
years from a proposed regulatory agency requirement that, in
effect, would have required that cooling towers be installed at
the Bowline Point, Roseton and Indian Point units.  In return the
Company agreed to certain plant modifications, operating
restrictions and other measures and surrendered its operating
license for a proposed pumped-storage facility that would have
used Hudson River water.

     In September 1991, after the expiration of the 1981
settlement, three environmental interest groups commenced
litigation challenging the permit status of the units pending
renewal of their discharge permits, which expired in October
1992.  Under a consent order settling this litigation, certain
restrictions on the units' usage of Hudson River water have been
imposed on an interim basis.  Permit renewal applications were
filed in April 1992, after which the DEC determined that the
Company must submit a DEIS to provide a basis for determining new
permit conditions.  The DEIS, submitted in July 1993, includes an
evaluation of the costs and environmental benefits of potential
mitigation alternatives, one of which is the installation of
cooling towers.  After its review, the DEC will release for
public comment the DEIS and draft permit conditions.  Pending
issuance of final renewal permits, the terms and conditions of
the expired permits continue in effect.

     ELECTRIC AND MAGNETIC FIELDS.  Electric and magnetic fields
(EMF) are found wherever electricity is used.  Several scientific
studies have raised concerns that EMF surrounding electric
equipment and wires, including power lines, may present health
risks.  For additional information about EMF, see "Environmental
Matters - EMF" in Note F to the financial statements in Item 8.

<PAGE>
<PAGE>                        - 22 -

GENERAL

     STATE ANTITAKEOVER LAW.  New York State law provides that a
"resident domestic corporation," such as the Company, may not
consummate a merger, consolidation or similar transaction with
the beneficial owner of a 20 percent or greater voting stock
interest in the corporation, or with an affiliate of the owner,
for five years after the acquisition of the voting stock
interest, unless the transaction or the acquisition of the voting
stock interest was approved by the corporation's board of
directors prior to the acquisition of the voting stock interest. 
After the expiration of the five-year period, the transaction may
be consummated only pursuant to a stringent "fair price" formula
or with the approval of a majority of the disinterested
stockholders.

EMPLOYEES

     The Company had 16,582 employees on December 31, 1995. 
Approximately two-thirds of the employees are represented by a
union whose collective bargaining agreement with the Company
expires on June 22, 1996.  An additional 2.3 percent of the
employees are represented by another union whose collective
bargaining contract expires on June 21, 1997.

RESEARCH AND DEVELOPMENT

     For information about the Company's research and development
costs, see Note A to the financial statements in Item 8.
<PAGE>
<PAGE>                        - 23 -
<TABLE>

OPERATING STATISTICS
===============================================================================================
<S>                                  <C>         <C>         <C>         <C>         <C>
Year Ended December 31                     1995        1994        1993        1992        1991
-----------------------------------------------------------------------------------------------
ELECTRIC Energy Generated
  Purchased and Sold (MWhrs):                     
    Generated (a)                    18,436,798  20,419,828  20,079,995  24,157,503  23,989,334  
    Purchased from Others (a)        26,700,594  21,036,437  19,813,654  14,360,373  15,238,100  
      Total Electric Energy
        Generated and Purchased      45,137,392  41,456,265  39,893,649  38,517,876  39,227,434  
    
    Less:
       Electric energy supplied
         without direct charge               71          73          74          75          74  
       Electric energy used by
         Company (b)                    165,934     134,940     183,903     173,834     157,079   
       Distribution losses and
         other variances              2,977,547   2,762,315   2,863,828   2,781,046   2,786,547   
    
        Total Electric Energy
          Sold (c)                   41,993,840  38,558,937  36,845,844  35,562,921  36,283,734   

Electric Energy Sold (MWhrs):
    Residential                      10,848,648  10,660,148  10,512,496   9,845,397  10,380,814    
    Commercial and Industrial        25,492,489  25,511,974  25,118,125  24,680,600  24,930,864    
    Railroads and Railways               47,482      47,289      49,542      50,934      46,726    
    Public Authorities                  569,749     554,753     560,836     542,358     531,272    
       Total Sales to Con
         Edison Customers            36,958,368  36,774,164  36,240,999  35,119,289  35,889,676    
    Delivery Service to
      NYPA Customers and Others       8,855,790   8,773,155   8,441,624   8,187,292   8,241,174    
    Service for Municipal
      Agencies                          456,728     413,893     361,854     287,489     681,791    
       Total Sales in
         Franchise Area              46,270,886  45,961,212  45,044,477  43,594,070  44,812,641  
    Off-System Sales (a) (d)          5,035,472   1,784,773     604,845     443,632     394,058    

Average Annual kWhr Use Per
  Residential Customer (e)                4,188       4,136       4,104       3,872       4,116    

Average Revenue Per kWhr
  Sold (cents):
    Residential (e)                        16.1        15.8        16.0        15.0        14.7   
    Commercial and Industrial (e)          12.5        12.2        12.6        12.0        11.9    


(a)  Amount generated in 1995 includes 3,159,047 MWhrs generated for others, which is also included in
     1995 off-system sales.  Amounts purchased in 1995 includes 2,666,837 MWhrs of such electric energy 
     subsequently purchased by the Company.  See "Electric Operations - Gas Conversions", above.

(b)  1995, 1993, 1992 and 1991 electric energy used by the Company includes MWhrs of 436, 29,233,
     30,859 and 9,354 supplied to NYPA.  Electric energy used by the Company in 1994 includes
     21,275 MWhrs received from NYPA.

(c)  Includes off-system sales.

(d)  1995, 1994, 1993, 1992 and 1991 include MWhrs of 2,825, 350, 2,142, 52,929 and 4,982 which were
     sold to NYPA and are also included in the Delivery Service to NYPA.

(e)  Includes Municipal Agency sales.
<PAGE>
<PAGE>                        - 24 -

OPERATING STATISTICS
=============================================================================================== 
<S>                            <C>          <C>          <C>          <C>           <C>
Year Ended December 31                 1995         1994         1993         1992         1991
-----------------------------------------------------------------------------------------------
GAS (Dth) (a):
  Purchased (b)                 217,269,541  208,328,267  214,719,241  221,181,200  222,730,835  
  Storage - net change            9,469,767   (4,410,363)     222,559      752,561   (2,691,256) 
    Used as boiler fuel
      at Electric and Steam
      Stations (b)             (110,761,124) (92,680,221)(108,153,436)(116,951,577)(121,773,852)
    Gas Purchased for Resale    115,978,184  111,237,683  106,788,364  104,982,184   98,265,727 

  Less:
     Gas used by Company            237,688      221,715      203,793      153,537      150,387 
     Off-System Sales & NYPA (c)  4,887,971         --           --           --           --
     Distribution losses and
       other variances            4,655,387    2,443,486    3,998,234    3,856,836    5,563,386 

      Total Gas Sold            106,197,138  108,572,482  102,586,337  100,971,811   92,551,954 

Gas Sold (Dth) (a)
  Firm Sales
    Residential                  51,702,329   53,981,416   52,624,331   52,626,406   46,200,725 
    General                      39,021,997   39,365,003   37,214,994   36,656,433   33,539,780 
      Total Firm Sales           90,724,326   93,346,419   89,839,325   89,282,839   79,740,505 
  Interruptible Sales            15,472,812   15,226,063   12,747,012   11,688,972   12,811,449 
      Total Sales to Con 
        Edison Customers        106,197,138  108,572,482  102,586,337  100,971,811   92,551,954 
  Transportation of Customer-
    Owned Gas                    30,361,189   18,369,501   20,891,649   25,448,441   26,823,303 
  Off-System Sales                3,376,375         --           --           --           --
      Total Sales and
        Transportation          139,934,702  126,941,983  123,477,986  126,420,252  119,375,257 

Average Revenue Per Dth Sold (a):
  Residential                        $ 9.43       $ 9.85       $ 9.27       $ 8.41       $ 8.76 
  General                            $ 6.38       $ 7.05       $ 6.71       $ 6.03       $ 6.07 



STEAM Sold (Mlbs):               29,425,780   30,685,155   29,394,335   29,381,922   28,531,067 

Average Revenue per Mlbs Sold        $11.35       $11.10       $11.06       $10.63       $10.45 

Customers - Average for Year
  Electric                        2,994,447    2,980,026    2,964,716    2,950,614    2,938,201 
  Gas                             1,034,784    1,031,675    1,028,048    1,026,546    1,027,933 
  Steam                               1,945        1,964        1,973        1,970        1,975 


(a) Does not include amounts for the Company's gas marketing subsidiary.  See "Gas Operations - 
    Gas Sales", above.

(b) Includes 31,706,551 Dth provided by others.  See "Electric Operations - Gas Conversions", above.

(c) Includes 1,305,730 Dth for balancing transactions with NYPA.

</TABLE>             
<PAGE>
<PAGE>                                                          - 25 -
<TABLE>

FIVE-YEAR FORECAST

This page and the next page show actual 1995 amounts for certain operating and financial data and the Company's forecasts of such
data for the years 1996 through 2000.  Footnotes appear on the next page.  The forecast data (i) are forward-looking statements,
(ii) are estimates and not statements of fact, (iii) were developed by the Company, based on information available on or shortly
after December 31, 1995, including information and estimates provided by others, (iv) have not been reviewed and reported on by the
Company's independent accountants and (v) are subject to, and may be rendered materially inaccurate by, future events.  Important
factors that could cause actual results to differ materially from the forecast data include weather variations, changes in national,
regional, or local economic conditions or trends, changes in laws, regulations or regulatory policies, developments in legal or
public policy doctrines, technological developments and other presently unknown or unforeseen factors. See "Liquidity and Capital
Resources - Competition; 1995 Electric Rate Agreement - Return on Equity and Equity Ratio and  Modified ERAM; Clean Air Act
Amendments; Nuclear Fuel Disposal; and Impact of Inflation" in Item 7 and Notes A and F to the financial statements in Item 8.

       <S>                                     <C>            <C>       <C>       <C>       <C>       <C>
                                                Actual         Forecast  Forecast  Forecast  Forecast  Forecast
                                                 1995            1996      1997      1998      1999     2000


ENERGY SALES (a)

Electric - millions of kilowatthours
   Con Edison customers:
      Total before DSM (b)                                      40,326   40,965   41,578    42,142   42,976
      DSM (c)                                                   (3,307)  (3,649)  (3,960)   (4,283)  (4,607)
      Net Con Edison Customers                  36,958          37,019   37,316   37,618    37,859   38,369 
   NYPA customers (d)                            8,856           9,057    9,164    9,322     9,461    9,501
   Municipal Electric Agencies (e)                 457             474      490      580       580      580
         Total Service Area                     46,271          46,550   46,970   47,520    47,900   48,450

Gas - firm customers (f)
    (thousands of dekatherms)                   90,724          96,500   97,600   99,500   101,000  103,600

Steam (millions of pounds)                      29,426          29,700   29,980   29,990    29,900   30,000


PEAK LOAD (g)

Electric - peak hour load - megawatts
   Con Edison customers:
      Total before DSM (b)                                      10,236   10,438   10,640   10,858    11,058
      Load Modification Programs (h)               (i)             (25)     (40)     (50)     (75)     (100)
      DSM (j)                                                     (969)  (1,082)  (1,176)  (1,270)   (1,362)
      Net Con Edison Customers                   9,216           9,242    9,316    9,414    9,513     9,596
   NYPA customers (d)                            1,543           1,610    1,640    1,660    1,690     1,710
   Municipal Electric Agencies (e)(k)               46              73       89      111      117       119
         Net Service Area Peak Load             10,805(l)       10,925   11,045   11,185   11,320    11,425

Gas - firm customers (m)
    (thousands of dekatherms per day)              739             865      885      900      920       940
 
Steam (millions of pounds per hour)(n)            11.0            12.4     12.4     12.4     12.4      12.4


CAPABILITY

Electric (net megawatts at summer peak)
    Con Edison generation                        8,589           8,582    8,452    8,452    8,452     8,452
    Firm purchases - IPPs (o)                    1,796           1,984    2,024    2,053    2,053     2,053
    Firm purchases - Short-term capacity           400               0        0        0        0       295
    Firm purchases - NYPA & Hydro-Quebec (p)     1,113           1,113    1,113    1,113      733       525
         Con Edison capacity resources          11,898          11,679   11,589   11,618   11,238    11,325
    Capacity for NYPA customers(d)               2,217           2,210    2,217    2,243    2,250     2,460
         Total Service Area                     14,115          13,889   13,806   13,861   13,488    13,785

Gas - firm supply
     (thousands of dekatherms per day)             909             909      939      939      939       969
 
Steam (millions of pounds per hour)               13.2            13.3     13.3     13.3     13.3      13.3
<PAGE>
<PAGE>                                                                    - 26 -
           <S>                                 <C>          <C>       <C>        <C>        <C>       <C>        <C>
                                                Actual      Forecast  Forecast   Forecast   Forecast  Forecast    Forecast
                                                 1995         1996      1997       1998       1999      2000    5 Year Total
CAPITAL REQUIREMENTS AND MATURING SECURITIES
                                                                  (millions of dollars)
Construction Expenditures
     Electric                                    $456         $431      $422       $382       $389      $407     $2,031
     Gas                                          110          108       101        101         99        98        507
     Steam                                         28           31        30         26         27        15        129
     Common                                        99          108       118        102         85        80        493
     Total Construction Expenditures (q)          693          678       671        611        600       600      3,160

Enlightened Energy program - net                  (26)         (15)      (33)       (45)       (51)      (55)      (199)
Power contract termination costs - net (r)        (55)         (31)      (39)        (6)         -         -        (76)
Nuclear decommissioning trust (s)                  19           21        21         21         21        21        105
Nuclear fuel expenditures                          13           24        44         61         14        58        201
Investment in gas marketing subsidiary              2           10        10          -          -         -         20
     Subtotal                                     646          687       674        642        584       624      3,211

Retirements of Long-Term Debt (t)                  11          184       106        200        225       275        990

     Total                                       $657         $871      $780       $842       $809      $899     $4,201

PRINCIPAL NON-CASH CHARGES AND CREDITS TO INCOME
     (million of dollars)

Book depreciation and amortization                456          482       504        524        536       520      2,566
Amortization of nuclear fuel                       20           31        27         32         30        38        158
Deferred taxes                                     78           60        51         34         57        29        231
Deferred Investment Tax Credits                    (9)          (9)       (9)        (9)        (9)       (9)       (45)
Allowance for equity and borrowed
  funds used during construction                    6            5         7          7          9         5         33

--------------------------------
FOOTNOTES TO FIVE-YEAR FORECAST
(a)  Forecasts for 1996-2000 assume normal weather conditions.
(b)  Does not include off-system sales.
(c)  For 1996-2000, this represents anticipated sales reduction resulting from Company sponsored demand side management and
     non-rebate induced conservation, cumulative since 1990.
(d)  See "Electric Operations - NYPA," above.
(e)  See "Electric Operations - Municipal Electric Agencies", above.
(f)  In addition, actual sales to interruptible gas customers in 1995 amounted to 15,473 thousands of dekatherms.  Off-system
     sales in 1995 amounted to 3,376 thousands of dekatherms.  See "Gas Operations - Gas Sales", above.
(g)  Forecasts for 1996-2000 assume design weather conditions.
(h)  For 1996-2000, this represents anticipated load reduction resulting from the Company sponsored curtailable electric service
     and real time pricing programs.  
(i)  At 1995 peak, an estimated 28 MW of load reduction resulted from the Company sponsored curtailable electric
     service program.
(j)  For 1996-2000, this represents anticipated load reduction resulting from Company sponsored demand side management and
     non-rebate induced conservation, cumulative since 1990.
(k)  Includes electric demand of economic development customers.
(l)  At design weather conditions, the 1995 peak electric load would have been 10,850 MW.
(m)  Reflects the gas supply year which begins on November 1 of each calendar year shown.  "Actual" peak day demand shown for 1995
     is preliminary and assumes that peak day demand for the period occurred prior to March 20, 1996.
(n)  Reflects the winter season beginning in the year shown.  "Actual" peak steam demand shown for 1995 assumes that peak day demand
     for the winter occurred prior to March 20, 1996.
(o)  See "Liquidity and Capital Resources - Electric Capacity Resources and
     Competition" in Item 7 and Note G to the financial statements in Item 8.
(p)  See "Electric Operations - NYPA and Hydro-Quebec", above.
(q)  Assumes cost escalation at an average annual rate of 4.0 percent throughout the forecast period.
(r)  See "Liquidity and Capital Resources - 1995 Electric Rate Agreement - IPP Termination Costs" in Item 7.
(s)  See Note A to the financial statements in Item 8 for discussion of nuclear decommissioning costs.
(t)  Does not reflect refundings in advance of maturity.
</TABLE>
<PAGE>
<PAGE>                         - 27 -

ITEM 2.  PROPERTIES

     At December 31, 1995, the capitalized cost of the Company's
utility plant, net of accumulated depreciation, (and excluding
$85.2 million of nuclear fuel assemblies) was as follows:

                         Net Capitalized Cost     Percentage of 
Classification          (millions of dollars)   Net Utility Plant
In Service:
   Electric:
     Generation                $ 1,808.3                   17%
     Transmission                1,135.6                   11%
     Distribution                4,999.7                   47%
   Gas                           1,199.2                   11%
   Steam                           389.0                    4%
   Common                          820.7                    7%
Held For Future Use                 16.2                    -
Construction Work in Progress      360.5                    3%
Net Utility Plant              $10,729.2                  100%

ELECTRIC FACILITIES

     GENERATING FACILITIES.  As shown in the following table, at
December 31, 1995, the Company's net maximum generating capacity
(on a summer rating basis) was 8,533 MW, without reduction to
reflect the unavailability or reduced capacity at any given time
of particular units because of maintenance or repair or their use
to produce steam for sale.  For information about the electric
energy purchased by the Company, see "Electric Operations" in
Item 1.

Generating      Net Generating Capacity   Percentage of Electric
Stations         at December 31, 1995     Energy Generated and
               (Megawatts-Summer Rating)  Purchased in 1995*
Fossil-Fueled
Ravenswood (3 Units)      1,742                 7.1%
Astoria (3 Units)         1,075                10.3%
Arthur Kill (2 Units)       826                 2.3%
East River (3 Units)        430                 1.6%
Bowline Point (2 Units)
  - two-thirds interest     803                 4.3%
Roseton (2 Units)
  - 40% interest            482                 1.4%
Other (5 Units)             231                 1.8%
  Subtotal                5,589                28.8%
Nuclear - Indian Point      931                10.8%
Gas Turbines (39 Units)   2,013                 1.3%
  Total                   8,533                40.9%

* Reflects amounts relating to electricity generated for others.
See "Electric Operations - Gas Conversions" in Item 1.
<PAGE>
<PAGE>                          - 28 -

     The Company's fossil-fueled plants burn natural gas or
residual oil.  Most of the gas turbines burn distillate oil.  
Certain units have the capability to burn either natural gas or
oil, and certain units can be converted to burn coal.  See "Fuel
Supply" in Item 1.

     For information about the Company's Indian Point 2 nuclear
unit, see "Electric Operations", "Fuel Supply - Nuclear Fuel",
"Environmental Matters and Related Legal Proceedings  - Indian
Point and Cooling Towers" in Item 1, "Liquidity and Capital
Resources - Capital Requirements" in Item 7 and Notes A and F to
the financial statements in Item 8.

     The Company's generating stations are located in New York
City with the exception of the Indian Point station in
Westchester County, New York; the Bowline Point station in
Rockland County, New York; and the Roseton station in Orange
County, New York.

     The Company's electric and steam generating stations are
held in fee with the following exceptions:  (i) Orange and
Rockland Utilities, Inc. ("O&R") has a one-third interest and the
Company has a two-thirds interest as tenants in common in the
Bowline Point station, which is operated by O&R;  (ii) Central
Hudson Gas & Electric Corporation ("Central Hudson") has a 35
percent interest, Niagara Mohawk Power Corporation ("Niagara
Mohawk") has a 25 percent interest and the Company has a 40
percent interest as tenants in common in the Roseton station
(which is operated by Central Hudson), with Central Hudson having
the right to acquire the Company's interest in 2004; and (iii)
the Company leases from trusts in which it owns the remainder
interests certain gas turbine generating facilities of which the
Company can assume direct ownership upon expiration of the leases
in 1996 and 1997.


<PAGE>
<PAGE>                        - 29 -

     TRANSMISSION FACILITIES.  The Company has transmission
interconnections with Niagara Mohawk, Central Hudson, O&R, New
York State Electric and Gas Corporation, Connecticut Light and
Power Company, Long Island Lighting Company, NYPA and Public
Service Electric and Gas Company.  The Company's transmission
facilities are located in New York City and Westchester, Orange,
Rockland, Putnam and Dutchess counties in New York State.

       At December 31, 1995, the Company's transmission system
had approximately 432 miles of overhead circuits operating at
138, 230, 345 and 500 kilovolts and approximately 378 miles of
underground circuits operating at 138 and 345 kilovolts.  There
are approximately 267 miles of radial subtransmission circuits
operating at 138 kilovolts.  The Company's 15 transmission
substations, supplied by circuits operated at 69 kilovolts and
above, have a total transformer capacity of 15,632 megavolt
amperes.

     At December 31, 1995, the transmission capacity to receive
power from outside New York City to supply in-City load during
the summer peak period was 4,915 MW.  The 1995 one-hour peak load
in the Company's service area was 10,805 MW, of which 9,476 MW
was for use within the City.  See "Electric Operations - Electric
Peak Load and Capacity" in Item 1.  In-City load in excess of
transmission capacity must be supplied by in-City generating
stations.  See  "Generating Facilities", above.

     DISTRIBUTION FACILITIES.  The Company owns various
distribution substations and facilities located throughout New
York City and Westchester County. At December 31, 1995, the
Company's distribution system had 294 distribution substations,
with a transformer capacity of 20,305 megavolt amperes, 32,255
miles of overhead distribution lines and 86,647 miles of
underground distribution lines.

GAS FACILITIES

     Natural gas is delivered by pipeline to the Company at
various points in its service territory and is distributed to
customers by the Company through approximately 4,200 miles of
mains and 359,000 service lines.  The Company owns a natural gas
liquefaction facility and storage tank at its Astoria property in
Queens, New York.  The plant can store approximately 1,000 mdth
of which a maximum of about 250 mdth can be withdrawn per day.
The Company has about 1,230 mdth of additional natural gas
storage capacity at a field in upstate New York, owned and
operated by Honeoye Storage Corporation, a corporation in which
the Company and two neighboring utilities own a controlling
interest.

<PAGE>
<PAGE>                        - 30 -

STEAM FACILITIES

     The Company generates steam for distribution at five
electric generating stations and two steam-only generating
stations and distributes steam to customers through approximately
87 miles of mains and 17 miles of service lines.

OTHER FACILITIES

     The Company also owns or leases various pipelines, fuel
storage facilities, office equipment, a thermal outfall structure
at Indian Point, and other properties located primarily in New
York City and Westchester, Orange, Rockland, Putnam and Dutchess
counties in New York State.

THE COMPANY MORTGAGE

     Substantially all the properties and franchises of the
Company, other than expressly excepted property, are subject to
the liens securing the Company's First and Refunding Mortgage
Bonds and the mortgage bonds of acquired companies.  As of
December 31, 1995, $176.5 million aggregate principal amount of
such mortgage bonds remained outstanding, of which $100 million
was paid at maturity in January 1996 and $75 million is scheduled
to mature in December 1996.  The Company has not issued mortgage
bonds since 1974.


ITEM 3.  LEGAL PROCEEDINGS

SUPERFUND

     The following is a discussion of significant proceedings
pending under Superfund or similar statutes involving sites for
which the Company has been asserted to have a liability.  The
list is not exhaustive and additional proceedings may arise in
the future.  For a further discussion of claims and possible
claims against the Company under the Federal Comprehensive
Environmental Response, Compensation and Liability Act of 1980
(Superfund) and the estimated liability accrued for certain
Superfund claims, see "Environmental Matters and Related Legal
Proceedings - Superfund" in Item 1, and "Environmental Matters -
Superfund" in Note F to the financial statements in Item 8.

     MAXEY FLATS NUCLEAR DISPOSAL SITE.  The United States
Environmental Protection Agency (EPA) advised the Company by
letter, dated November 26, 1986, that it was a potentially
responsible party (PRP) under Superfund for the investigation and
cleanup of the Maxey Flats Nuclear Disposal Site in Morehead,
Kentucky.  The site is owned by the State of Kentucky and was
operated as a disposal facility for low level radioactive waste 
<PAGE>
<PAGE>                        - 31 -
from 1963 through 1977 by the Nuclear Engineering Corporation
(now known as U.S. Ecology Corporation).  EPA's letter alleges
that various radionuclides and organic chemicals have been
released from the site into the environment.  In September 1991,
the EPA issued its Record of Decision ("ROD") for the site
cleanup program.  Phase one of the program requires, among other
things, the removal, treatment and on-site disposal of the
leachate that has accumulated in the site's waste burial trenches
and the installation of an impervious cover over the waste burial
trench area of the site, monitoring wells and erosion control and
surface water drainage systems.  Phase two requires a 100-year
stabilization period, with periodic monitoring and maintenance of
the cover, followed by installation of a permanent cap.

     In March 1995, the EPA, de minimis PRPs, large private party
PRPs, large federal agency PRPs and Kentucky entered into a
settlement agreement with respect to the costs of the cleanup
program.  Subject to court approval, the settlement agreement is
to be implemented pursuant to a consent decree. The Company has
agreed to be responsible for approximately 2.2 percent of the
costs allocable to the large private party PRPs.  The large
private party PRPs have agreed to implement phase one of the
program and any corrective actions required, during the ten years
following completion of phase one, to meet the performance
standards established in the ROD, and to share the costs of those
activities with the large Federal agency PRPs.  Also, if during
this ten-year period the EPA determines that horizontal flow
barriers are required, the large party PRPs will be required to
share the cost of such barriers.  The large party private PRPs
are not responsible for any costs after the ten year period
expires.  Kentucky will implement and fund the phase two program. 
The Company's share of the cleanup costs is estimated to be about
$500,000.  In addition, if horizontal flow barriers are required,
depending on their extent, the Company would be obligated to pay
an estimated $10,000 to $100,000.

     EASTERN DIVERSIFIED METALS SITE.  The EPA advised the
Company by letter, dated March 5, 1987, that it is one of 118
PRPs under Superfund for the investigation and cleanup of the
Eastern Diversified Metals Site in Hometown, Pennsylvania. 
Between 1966 and 1977, Diversified Industries used the site for a
copper wire salvaging operation which involved the disposal of
shredded wire insulation in a waste pile located on the site. 
The EPA alleges that various metals and organic chemicals have
been released from the waste pile into the environment.  A
preliminary ranking list appended to the EPA's letter indicates
that the Company is responsible for less than 0.03 percent of the
waste insulation material at the site.  An EPA-approved site
study has been performed by the site owner and a PRP allegedly
responsible for about 77 percent of the waste.  The Company has
accepted EPA's offer to settle the Company's liability for this
site by paying $11,000.
<PAGE>
<PAGE>                        - 32 -

     CURCIO SCRAP METAL SITE.  The EPA advised the Company, in a
letter received on August 11, 1987, that it had documented the
release of hazardous substances into the environment at the site
of Curcio Scrap Metal, Inc. in Saddle Brook, New Jersey, and that
the EPA had information indicating that the Company sent
hazardous substances (PCBs) to the site.  The Company provided
the EPA with records that indicated that the Company sold scrap
electric transformers to a metal broker who in turn sold them to
the owner of the site.  A site study indicated that chemical
contamination has occurred on a portion of the site.  Elevated
concentrations of PCBs and various organic compounds and metals
have been detected in the soil and PCBs and organic compounds and
metals have also been detected in the shallow groundwater beneath
the site.

     On September 30, 1991, the EPA issued a Unilateral
Administrative Order which required the Company and three other
PRPs to commence a soil cleanup of this site pursuant to the
EPA's Record of Decision, dated June 28, 1991.  This soil cleanup
has been completed.  The EPA has required additional groundwater
studies to determine whether the soil cleanup reduced or
eliminated the groundwater contamination detected during the site
study referred to above.  The Company's estimate of the cost of
the additional groundwater studies is $400,000.  The EPA has only
designated five PRPs for this site and, as a result, the Company
will be expected to pay a major share of the cleanup costs.

     METAL BANK OF AMERICA SITES.  The EPA advised the Company by
letter dated October 26, 1987 that it has reason to believe that
the Company was a supplier of used transformers to Metal Bank of
America Inc.'s recycling sites in Philadelphia during the late
1960s and thereafter.  One of the sites has been placed on the
EPA's national priority list under Superfund as a result of a
leak in a storage tank containing PCBs.  The EPA alleges that
PCBs have been found in the ground water, soils and in the
sediments of the adjoining Delaware River.  The Company has
provided the EPA with documents which indicate that the Company
sold approximately 81 scrap transformers to a broker who, in
turn, delivered them to the site.  Under a steering committee
("PRP Group") participation agreement, the Company is responsible
for 1.48% of the expense of the remedial investigation and
feasibility study, which has been completed under an EPA
administrative consent order.  The Company's share of the cost of
the study was about $80,000.  In July 1995, EPA issued its
proposed site cleanup plan for public comment.  EPA's proposed
plan calls for other things, the removal and disposal of PCB and
TPH-contaminated sediments, the construction of a sheet pile wall
along the site's shoreline area, and the removal and off-site
disposal of various site soils that contain 25 ppm or more of PCB
and/or 10,000 ppm or more of total petroleum hydrocarbons 
<PAGE>
<PAGE>                        - 33 -

("TPH").  Although EPA estimated the cost of its plan at about
$17.2 million, the PRP Group believes that the plan could cost as
much as $28.8 million to implement and has requested EPA to
reconsider various aspects of the plan, including the 10,000 ppm
TPH cleanup standard and off-site disposal requirement for soil
located in the southern portion of the site.

     NARROWSBURG SITE.  In 1987, the New York State Attorney
General notified the Company that he has evidence that the
Company is a PRP under Superfund for hazardous substances that
have been released at the Cortese landfill in Narrowsburg, 
Sullivan County, New York.  The Cortese landfill is listed on the
EPA's national priorities list.  Company records indicate that  
drums containing non-nuclear waste were shipped from Indian Point
to the Cortese landfill for disposal.  The Attorney General has
commenced an action under Superfund in the United States District
Court for the Southern District of New York against the Cortese
site owner and operator and SCA Services, an alleged transporter
of hazardous substances to the site.  On January 17, 1989, SCA
Services commenced a third-party action for contribution against
the Company and five other parties whose chemical waste was
allegedly disposed of at the site.  In 1990, SCA served a second
amended third-party complaint in which it sued the Company and 27
other third-party defendants for contribution.  The Company and
SCA Services have reached a settlement of the third-party action
under which the Company's sole responsibility will be to pay 6%
of the first $25 million of remedial costs at the site.  SCA
Services has agreed to indemnify the Company for any other
remedial costs that it has to pay.  The EPA recently selected an
estimated $12 million cleanup program for the site.  SCA, the
Company and various other third-party defendants with which SCA
settled entered into a Consent Decree under which they agree to
implement the cleanup program, to pay the EPA's oversight costs
for the site and to pay approximately $220,000 for natural
resource damages.  The Consent Decree has been filed with the
United States District Court for the Southern District of New
York, but cannot be entered and approved by the court until it
has been published for public comment as required under
Superfund.

     CARLSTADT SITE.  On August 20, 1990, the Company was served
with a third-party complaint in a Superfund cost contribution
action for a former waste solvent and oil recycling facility
located in Carlstadt, New Jersey.  The complaint, which is
pending before the United States District Court for the District
of New Jersey, alleges that the Company shipped 120,000 gallons
of waste oil to this site and that the Company is one of several
hundred parties who are responsible under Superfund for the study
and cleanup of the facility.  The plaintiffs in the action, which
include a group of former customers of the facility, have
completed a $3 million remedial investigation and feasibility 
<PAGE>
<PAGE>                        - 34 -

study for the site.  Plaintiffs estimate that 7 to 15 million
gallons of waste solvents and oil were recycled at the site and
based on this estimate, the Company's share of the cleanup costs
would be about one percent.  The costs of the cleanup
alternatives that were evaluated in the remedial investigation
and feasibility study range from $8 million to $321 million.  In
1990, the EPA selected an interim remedy to control release from
the site while the EPA evaluates and develops a final cleanup
remedy.  The interim remedy called for, among other things, the
construction of a slurry wall around the site and an infiltration
barrier over the site.  EPA estimated that the interim remedy
would cost about $3 million to implement.  Plaintiffs claim that
the interim remedy cost $10 million to complete.

     HELEN KRAMER LANDFILL SITE.  In September 1991, Orange and
Rockland Utilities, Inc. (O&R) was served with third-party
complaints in consolidated Superfund cost recovery contribution
actions for the Helen Kramer Landfill Site in Mantau, New Jersey.
The complaints, which are pending before the United States
District Court for the District of New Jersey, allege that, in
1974, Marvin Jonas, Inc. transported hazardous substances for O&R
and disposed of those substances in the Helen Kramer Landfill. 
Preliminary investigation by O&R indicates that waste materials
generated during the construction of the Bowline Point generating
station were hauled and disposed of by Marvin Jonas, Inc. in
1974.  The Company owns a two-thirds interest in Bowline Point. 
O&R, which operates Bowline Point, owns the remaining one-third
interest.  Bowline Point liabilities are shared by the Company
and O&R in accordance with their respective ownership interests. 
The EPA has commenced cleanup of this site and the total site
cleanup cost is estimated at $150 million.  Assuming that all of
the Bowline wastes alleged to have been disposed of at the site
were so disposed of, they represent about 0.4% of the total
volume of waste-in at the site.  On this basis, the Company's
share of the cleanup cost is estimated at $400,000.

     GLOBAL LANDFILL SITE.  The Company has been designated a PRP
under Superfund and the New Jersey Spill Compensation and Control
Act (Spill Act) for the study and cleanup of the Global Landfill
Site in Old Bridge, New Jersey.  This 65-acre municipal and
industrial waste landfill is included on the Superfund National
Priorities List and is being administered by the New Jersey
Department of Environmental Protection and Energy (NJDEPE)
pursuant to an agreement between the EPA and the State of New
Jersey.

<PAGE>
<PAGE>                        - 35 -

     The Company provided EPA with records indicating that it had
disposed of approximately ten cubic yards of waste asbestos at
the site in February 1984.  In August 1989, the NJDEPE served the
Company with a Spill Act directive that required the Company and
40 other PRPs to fund a $1.5 million remedial investigation and
feasibility study for the site.  A PRP Group was formed and the
Group entered into a settlement agreement and an administrative
consent order with NJDEPE that, among other things, required the
PRP Group's members to contribute $500,000 towards the cost of
the study.  The Company's share of the PRP Group's payment to the
NJDEPE was $5,000.

     In February 1991, the EPA and the NJDEPE proposed a $30
million interim remedy for the site.  This remedy calls for the
installation of gas and leachate collection and treatment systems
at the landfill and the construction of an impervious cover over
the landfill (Phase I).  It also calls for further studies to
determine the alternatives for addressing groundwater and
wetlands contamination in the vicinity of the landfill (Phase
II).  In March 1991, the NJDEPE served the Company with a second
Spill Act Directive that requires the Company and the other 
members of the PRP Group to pay for the implementation of the
Phase I remedy for the site.  The PRP Group entered into a
Consent Decree with the NJDEPE under which they agreed to
implement the Phase I remedy with partial funding to be provided
by the NJDEPE.  The Company's share of the cost is estimated at
$150,000.

     CHEMSOL SITE.  By letter dated December 20, 1991, the EPA
advised the Company that it had documented the release of
hazardous substances at the Chemsol Site in Piscataway, New
Jersey and that it had reason to believe that the Company sent
waste materials to the site during the 1960 to 1965 period.  In
response to EPA's demand for records, including any relating to
Cenco Instruments Corp., the Company submitted to EPA records of
payments to Central Scientific Company, a Division of Cenco
Instruments Corp. during the 1960-1965 period.  The Company is
unable at this time to determine either the purpose of the
payments to Central Scientific Company or the connection of that
company to the site.  The EPA has not designated the Company as a
PRP and has not yet selected a final cleanup program for the
site.  However, the EPA has selected an interim remedy, expected
to cost about $8 million, for the site groundwater contamination
and has ordered several designated PRPs to implement that remedy.

<PAGE>
<PAGE>                        - 36 -

     ECHO AVENUE SITE.  In December 1987, the DEC classified the
Company's former Echo Avenue Substation Site in New Rochelle, New
York as an "Inactive Hazardous Waste Disposal Site."  The basis
for this classification was the presence of PCBs in the soil and
in the buildings on the site.  Although the Company has cleaned
up the PCBs on the site, the DEC requires a thorough site survey
before it will remove the site from the Inactive Hazardous Waste
Disposal Site list.  Under a consent order with the DEC a new
site survey was done and remedial action taken.  The cost to the
Company of this additional work was $213,000.  The Company
demolished its building on this site, and expects to incur
approximately $1 million in additional cleanup expenses.

     In January 1992, the owners of Echo Bay Marina filed suit in
Federal court alleging that PCBs were being discharged from the
Echo Avenue site into Long Island Sound.  Plaintiffs are seeking
a declaration that the Company is in violation of the Clean Water
Act, civil penalties of $25,000 per day for each violation,
remediation costs, an injunction against further discharges,
legal fees, and compensatory damages of $24 million.  In December
1994, the court dismissed plaintiffs claims for property damage,
including loss of business.  Pretrial discovery on the remaining
claims is continuing.

     C&D RECYCLING SITE.  On July 13, 1992, the Company received
a letter from the EPA stating that it is a PRP with respect to
the C&D Recycling site located in Foster Township, Luzerne
County, Pennsylvania.  In 1979, the Company retained C&D
Recycling Company to recover copper and lead from a shipment of
30,560 pounds of scrap electric cable.  It appears that the bulk
of the scrap cable sent to this site was generated by AT&T Nassau
Metals, a subsidiary of AT&T.  The total cleanup cost is
estimated at $12.5 million.  In March 1995, the EPA advised the
Company, that based on the information currently available to it,
the Company is responsible for 0.0297% of the scrap cable at this
site.  On October 15, 1995, the Company entered into an EPA
administrative consent order under which it agreed to pay $6,385
in full settlement of all past and future Superfund response
costs for the site.  The order will not become effective until it
has been issued for public comment and approved by the United
States Department of Justice.
<PAGE>
<PAGE>                        - 37 -
     PCB TREATMENT, INC., SITES.  On September 30, 1994, the
Company received a letter from the EPA indicating that it had
been identified as a PRP for the PCB Treatment, Inc. ("PTI")
Sites in Kansas City, Kansas and Kansas City, Missouri.  The
sites--a vacant, five-story building at 45 Ewing Street (K.C.,
Kansas) and a partially-occupied, seven-story building at 2100
Wyandotte Street (K.C., Missouri)-- were used by PTI from 1982
until 1987 for the storage, processing, and treatment of PCB-
containing electric equipment, dielectric oils, and materials. 
According to the EPA, the buildings' floor slabs and ceilings and
the soil areas outside the buildings' loading docks are
contaminated with PCBs.  The EPA estimates that approximately
1,400 facilities shipped materials to the sites.

     On October 21, 1994, the EPA held a PRP meeting for the
sites and requested the PRPs to form a steering committee and to
consider conducting a cleanup program for the sites under the
auspices of the Toxic Substances Control Act, or failing that,
performing a Superfund cleanup for the sites.  At the meeting,
the EPA provided the Company with waste manifests and other
documents indicating that the Company was responsible for 141,090
pounds (about 0.7%) of the approximately 20.3 million pounds of
PCB-containing equipment, oil, and materials that PTI records
(which the EPA had obtained) indicate were shipped to the 2100
Wyandotte Street Site.  In August 1995, EPA served Superfund
information requests on the known PRPs for the sites.  The
Company's investigation indicates that it shipped approximately
110,390 pounds of PCB-containing equipment and 96,000 pounds of
PCB-contaminated mineral oil to the 2100 Wyandotte Street site. 
It shipped approximately 2.63 million pounds of PCB-containing
equipment to the 45 Ewing Street site for processing prior to the
equipment's disposal at off-site facilities.  The EPA is still
reviewing the PRPs' responses to the information requests and has
not yet issued a waste-in list for the 45 Ewing Street site or
revised its waste-in list for the 2100 Wyandotte Street site. 
Accordingly, the Company's share of the cleanup costs for these
sites can not be determined.  In September 1995, EPA met with
PRPs and requested them to conduct additional studies at the
sites under an administrative consent order.  The Company and
several other site PRPs are forming a steering committee for the
purpose of negotiating the administrative consent order with EPA
and performing the studies.  PRPs that are government agencies
are expected to join into that order and help fund the studies.

     PELHAM MANOR SITE.  Prior to 1968, the Company and its
predecessor companies operated a manufactured gas plant (MGP) on
a site located in Pelham Manor, Westchester County.  Soil and
groundwater tests by the current owners and lessees indicate the
presence of hazardous substances which are associated with the
MGP process.  The Company has agreed to participate with the site
owners and lessees in further site studies to develop and
implement a cleanup plan that will be acceptable to the DEC.
<PAGE>
<PAGE>                        - 38 -

     ASTORIA SITE.  The Federal Resource Conservation and
Recovery Act delegates to the states licensing authority for PCB
storage.  As a condition to renewal by the DEC of the Company's
permit to store PCBs at the Company's Astoria generating station,
the Company is required to conduct a site investigation and,
where necessary, a remediation program.  The site investigation
commenced in April 1994 and is scheduled to be completed in late
1997.  The cost of the investigation is estimated at
approximately $5 million.  The extent and cost of the remediation
program will depend on the results of the investigation.

     HUNTS POINT SITE.  In September 1994, the City of New York
notified the Company that it had discovered coal tar on the site
of a former Company manufactured gas plant in the Hunts Point
section of The Bronx.  The Company had manufactured gas at that
location prior to its sale of the site to the City in the 1960s. 
The Company has agreed to conduct a site study and to develop and
implement a remediation program.  However, the Company has not
agreed to pay costs not associated with the Company's use of the
site.  The Company is unable at this time to estimate its
exposure to liability with respect to this site.

     ANCHOR MOTOR SITE.  In November 1995, Anchor Motor Freight,
Inc. notified the Company that it had discovered coal tar on its
site in Westchester County.  Anchor requested that the Company
remediate the site.  A predecessor of the Company had
manufactured gas at that location.  The Company's preliminary
estimate is that the cost of remediating the site will be at
least $4 million.

TOXIC SUBSTANCES CONTROL ACT

     In November 1994, BCF Oil Refining, Inc., a processor and
re-refiner of used oil products and waste containing oil, brought
suit in federal court against the Company and four transporters
of waste oil products alleging that the defendants (primarily the
Company) caused PCB contaminated waste to be shipped to BCF
thereby contaminating its facilities.  In addition to the
remediation of BCF's facilities under the Federal Toxic
Substances Control Act, the suit seeks compensatory damages of
not less than $12.5 million from all the defendants and
additional punitive damages of not less than $12.5 million from
the Company.  Pre-trial discovery began in January 1995 and is
continuing.

<PAGE>
<PAGE>                        - 39 -

GRAMERCY PARK

     On August 19, 1989, a Company steam main exploded in the
Gramercy Park area of Manhattan, releasing debris containing
asbestos into that area.  The Company took responsibility for the
asbestos cleanup and most of the cost of that cleanup was covered
by the Company's insurance.

     A Federal Grand Jury in the Southern District of New York
issued an indictment in December 1993, which was superseded by an
indictment issued in April 1994, charging the Company and two of
its retired employees with criminal acts relating to the
reporting of the release of asbestos from the steam main
explosion.  The April 1994 indictment contained eight counts.

     In April 1995, the Company was sentenced to a fine of
$500,000 on each of four counts and to three years probation,
during which time the Company's compliance with environmental
laws will be monitored by a court-appointed monitor.  

DEC PROCEEDING

     For information about this proceeding, see "Environmental
Matters - DEC Settlement" in Note F to the financial statements
in Item 8 and "Results of Operations - Other Operations and
Maintenance Expenses" in Item 7.

ASBESTOS LITIGATION

     For a discussion of asbestos and suits against the Company
involving asbestos, see "Environmental Matters and Related Legal
Proceedings - Asbestos" in Item 1, and "Environmental Matters -
Asbestos Claims" in Note F to the financial statements in Item 8. 
The following is a discussion of the significant suits involving
asbestos in which the Company has been named a defendant.  The
listing is not exhaustive and additional suits may arise in the
future.

     MASS TORT CASES.  Numerous suits have been brought in New
York State and Federal courts against the Company and many other
defendants for death and injuries allegedly caused by exposure to
asbestos at various Company premises.  Many of these suits have
been disposed of without any payment by the Company, or for
immaterial amounts.  The amounts specified in the remaining
suits, including the Moran v. Vacarro suit discussed below, total
billions of dollars, but the Company believes that these amounts
are greatly exaggerated, as were the claims already disposed of.

<PAGE>
<PAGE>                        - 40 -

     MORAN, ET AL. V. VACARRO, ET AL.  On May 9, 1988, the
Company was served with a complaint in an action in the New York
State Supreme Court, New York County, in which approximately 184
Company employees and their union alleged that the employees were
exposed to dangerous levels of asbestos as a result of alleged
intentional conduct of supervisory employees.  Each of the
employee plaintiffs seeks $1 million in punitive damages,
unspecified additional compensatory damages, and to enjoin the
Company from violating EPA regulations and exposing employees to
asbestos without first taking certain safety measures.  On May
16, 1988, the complaint was amended to add a claim by each
employee plaintiff for $1 million in damages for mental distress. 
In November 1988, the complaint was amended to add four
additional employee plaintiffs.  On July 9, 1990, the complaint
was amended to add the spouses of 131 plaintiffs as additional
plaintiffs and to remove the union as a plaintiff.  Each spouse
seeks medical monitoring, $1 million for emotional distress and
$1 million for punitive damages.  On January 19, 1995, the court
dismissed the claims of the employee plaintiffs, leaving employee
spouses as the only plaintiffs.

RATE PROCEEDINGS

     For information concerning proceedings relating to the
Company's rates, see "Regulation and Rates" in Item 1.

NUCLEAR FUEL DISPOSAL

     Reference is made to the information under the caption
"Liquidity and Capital Resources - Nuclear Fuel Disposal" in Item
7 for information concerning a suit brought by the Company and a
number of other utilities against the United States Department of
Energy.  The suit is entitled Northern States Power Co., et al.
v. Department of Energy, et al.


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

     None.


<PAGE>
<PAGE>                        - 41 -


                  EXECUTIVE OFFICERS OF THE REGISTRANT

     The names of the executive officers of the Company together
with their ages and the positions and offices with the Company
held by them as of March 1, 1996, the respective dates they
became executive officers and their business experience during
the past five years (or since they became executive officers, if
earlier) are set forth below.  Under the Company's By-laws,
officers of the Company are elected to hold office until the next
election of Trustees (directors) of the Company and until their
respective successors are chosen and qualify, subject to removal
at any time by the Company's Board of Trustees.


                                Business Experience
Name, Age, Positions and        During the Past Five Years
Offices with the Company        or Since Becoming an
and Date First Became an        Executive Officer,
Executive Officer               If Longer

Eugene R. McGrath - 54          9/90 to present - Chairman of
 Chairman of the Board,           the Board, President, Chief
  President, Chief Executive      Executive Officer and Trustee
   Officer, and Trustee;        2/89 to 8/90 - President, Chief
    9/1/78                        Operating Officer and Trustee
                                10/87 to 1/89 - Executive Vice 
                                  President - Operations and
                                  Trustee
                                9/82 to 9/87 - Executive Vice
                                  President - Central Operations
                                3/81 to 8/82 - Senior Vice
                                  President - Power Generation
                                9/78 to 2/81 - Vice President
                                  - Power Generation

Raymond J. McCann - 61          2/89 to present - Executive Vice
 Executive Vice President         President and Chief Financial
  and Chief Financial             Officer, and Trustee
   Officer, and Trustee;        10/87 to 1/89 - Executive Vice
    5/15/72                       President - Finance and Law,    
                                  and Trustee
                                8/80 to 9/87 - Executive Vice
                                  President - Division Operations
                                6/77 to 8/80 - Vice President
                                  - Manhattan Division
                                6/76 to 5/77 - Vice President
                                  - Accounting and Treasury
                                3/74 to 5/76 - Controller
                                5/72 to 3/74 - General Auditor
<PAGE>
<PAGE>                         - 42 -

                                Business Experience
Name, Age, Positions and        During the Past Five Years
Offices with the Company        or Since Becoming an
and Date First Became an        Executive Officer,
Executive Officer               If Longer

J. Michael Evans - 50           7/95 to present - Executive Vice
  Executive Vice President        President - Customer Service
   - Customer Service;          4/95 to 6/95 - Executive Vice
     9/1/91                       President
                                9/91 to 3/95 - Executive Vice
                                  President - Central Operations
                                7/89 to 8/91 - Senior Vice
                                  President and Chief Operating
                                  Officer - Kansas City Power and
                                  Light

Charles F. Soutar - 59          7/95 to present - Executive Vice
  Executive Vice President        President - Central Services
   - Central Services;          2/89 to 6/95 - Executive Vice
     9/1/77                       President - Customer Service
                                3/85 to 1/89 - Executive Vice
                                  President - Central Services
                                5/80 to 2/85 - Senior Vice
                                  President - Construction,
                                  Engineering and Environmental
                                  Affairs
                                9/77 to 4/80 - Vice President
                                  - Central Services

Stephen B. Bram - 53            6/95 to present - Senior Vice
  Senior Vice President           President - Central Operations
   - Central Operations         12/94 to 3/95 - Senior Vice
     8/1/79                       President
                                9/94 to 11/94 - Vice President
                                12/87 to 8/94 - Vice President
                                  - Nuclear Power
                                9/82 to 11/87 - Vice President
                                  - Fossil Power
                                7/80 to 8/82 - Vice President
                                  - Central Substation, Systems
                                    Operations and Technical
                                    Services
                                8/79 to 6/80 - Vice President
                                  - Central Substation and
                                    System Operations
<PAGE>
<PAGE>                         - 43 -

                                Business Experience
Name, Age, Positions and        During the Past Five Years
Offices with the Company        or Since Becoming an
and Date First Became an        Executive Officer,
Executive Officer               If Longer

Carl W. Greene - 60             9/94 to present - Senior Vice
  Senior Vice President           President - Financial and
  - Financial and Regulatory      Regulatory Matters
    Matters;                    7/92 to 8/94 - Senior Vice
    6/1/76                        President - Accounting and
                                  Treasury
                                6/82 to 6/92 - Vice President and
                                  Controller
                                6/76 to 5/82 - Controller

Mary Jane McCartney - 47        10/93 to present - Senior Vice    
  Senior Vice President            President - Gas Operations
   - Gas Operations;            2/93 to 10/93 - Vice President
     12/1/90                       - Gas Supply
                                7/92 to 1/93 - Vice President 
                                   - Gas Business Development
                                12/90 to 6/92 - Vice President
                                   - Queens

Peter J. O'Shea, Jr. - 58       1/96 to present - Senior Vice
  Senior Vice President            President and General Counsel
   and General Counsel;         4/87 to 12/95 - Vice President
    1/1/96                         and Associate General Counsel
                                   -- ITT Corporation

Horace S. Webb - 55             9/92 to present - Senior Vice
  Senior Vice President           President - Public Affairs
   - Public Affairs;            1/90 to 8/92 - Vice President
     9/1/92                       - Communications and Public
                                  Affairs, Hoechst Celanese
                                  Corp.

Archie M. Bankston - 58         6/89 to present - Secretary and
  Secretary and Associate         Associate General Counsel
   General Counsel;             1/74 to 5/89 - Secretary and
    1/7/74                        Assistant General Counsel

John F. Cioffi - 62             7/92 to present - Treasurer
  Treasurer;                    6/87 to 6/92 - Assistant Vice     
   7/1/92                         President 
<PAGE>
<PAGE>                         - 44 -

                                Business Experience
Name, Age, Positions and        During the Past Five Years
Offices with the Company        or Since Becoming an
and Date First Became an        Executive Officer,
Executive Officer               If Longer

Lawrence F. Travaglia - 57      3/93 to present - General Auditor
  General Auditor;              10/80 to 2/93 - Assistant
   3/1/93                         Treasurer

John A. Arceri - 53             6/95 to present - Vice President
  Vice President                   - Energy Services
    Energy Services;            10/93 to 5/95 - Assistant Vice
     6/1/95                        President - Gas Business
                                   Development
                                3/90 to 9/93 - Assistant Vice
                                   President - Electrical
                                   Distribution

Robert A. Bell - 62             6/81 to present - Vice President
  Vice President                  - Research & Development
    Research & Development;
     6/1/81

David G. Bosland - 59           6/91 to present - Vice President
  Vice President                 - Staten Island Customer Service
   - Staten Island              3/83 to 6/91 Vice President
     Customer Service;            - Transportation & Stores
     3/1/83

Kevin M. Burke - 45             3/93 to present - Vice President
  Vice President                  - Corporate Planning
  - Corporate Planning;         3/90 to 2/93 - Vice President
    12/1/87                       - Brooklyn Customer Service
                                12/87 to 2/90 - Vice President
                                  - Construction

Richard P. Cowie - 49           3/94 to present - Vice President
  Vice President                  - Employee Relations
   - Employee Relations;        2/91 to 2/94 - Director - Central
     3/1/94                       Customer Service
                                9/90 to 1/91 - Assistant to the   
                                  Executive Vice President -      
                                  Customer Service
  

<PAGE>
<PAGE>                         - 45 -

                                Business Experience
Name, Age, Positions and        During the Past Five Years
Offices with the Company        or Since Becoming an
and Date First Became an        Executive Officer,
Executive Officer               If Longer

Robert F. Crane - 59            3/94 to present - Vice President  
  Vice President                  - Fuel Supply
   - Fuel Supply;               10/93 to 2/94 - Vice President 
     12/1/82                       - Gas Supply
                                2/93 to 10/93 - Vice President 
                                  - Gas Business Development
                                4/91 to 1/93 - Vice President 
                                  - Gas Supply
                                12/84 to 3/91 - Vice President 
                                   - Manhattan Division
                                12/82 to 11/84 - Vice President 
                                   - Queens Division

George J. Delaney - 60          2/96 to present - Vice President
  Vice President                   - Central Services
   - Central Services;          12/78 to 2/96 - Vice President
     5/28/74                       - Westchester Customer Service
                                9/74 to 11/78 - Vice President
                                   - Bronx Division     
                                5/74 to 8/74 - Vice President
                                  - Staten Island Division

Robert W. Donohue, Jr. - 53     2/94 to present - Vice President
  Vice President                  - Queens Customer Service
   - Queens Customer Service;   3/90 to 1/94 - Vice President
     3/1/90                       - Construction
  
Charles J. Durkin, Jr. - 52     12/93 to present - Vice President
  Vice President                   - Fossil Power
   - Fossil Power;              1/88 to 12/93 - Vice President
     9/1/82                       - Engineering
                                9/82 to 12/87 - Vice President
                                  - System and Transmission 
                                    Operations

Jacob Feinstein - 52            4/91 to present - Vice President
  Vice President                  - System & Transmission 
   - System & Transmission        Operations
     Operations;                12/88 to 3/91 - Plant Manager
     4/1/91 


<PAGE>
<PAGE>                         - 46 -

                                Business Experience
Name, Age, Positions and        During the Past Five Years
Offices with the Company        or Since Becoming an
and Date First Became an        Executive Officer,
Executive Officer               If Longer

Joan S. Freilich - 54           9/94 to present - Vice President,
  Vice President, Controller      Controller and Chief Accounting
   and Chief Accounting           Officer
   Officer;                     7/92 to 8/94 - Vice President
   12/1/90                        and Controller
                                12/90 to 6/92 - Vice President -
                                  Corporate Planning
  
David F. Gedris - 47            2/96 to present - Vice President
  Vice President                  - Westchester Customer Service
   - Westchester Customer       2/94 to 1/96 - Vice President
     Service;                     - Maintenance and Construction
     2/1/94                     7/92 to 1/94 - Assistant Vice
                                  President - Power Generation
                                  Maintenance
                                3/90 to 6/92 - Assistant Vice
                                   President - Steam Operations
                                
Garrett W. Groscup - 55         6/95 to present - Vice President
  Vice President                  - Brooklyn Customer Service
   - Brooklyn Customer          2/94 to 5/95 - Vice President
     Service;                     - Energy Services
     12/1/82                    4/91 to 1/94 - Vice President
                                  - Manhattan Customer Service
                                1/88 to 3/91 - Vice President
                                  - System & Transmission
                                    Operations
                                12/82 to 12/87 - Vice President
                                   - Engineering

William A. Harkins - 50         2/89 to present - Vice President
  Vice President                  - Planning and Inter-Utility
   - Planning and Inter-            Affairs
     Utility Affairs;       
     2/1/89                 
<PAGE>
<PAGE>                         - 47 -

                                Business Experience
Name, Age, Positions and        During the Past Five Years
Offices with the Company        or Since Becoming an
and Date First Became an        Executive Officer,
Executive Officer               If Longer

Paul H. Kinkel - 51             2/96 to present - Vice President
  Vice President                   - Maintenance and Construction
   - Maintenance and            12/93 to 2/96 - Vice President 
     Construction;                 - Engineering
     5/24/83                    12/87 to 12/93 - Vice President
                                   - Fossil Power
                                5/83 to 11/87 - Vice President
                                  - Construction

M. Peter Lanahan - 51           5/95 to present - Vice President
  Vice President                   - Environmental Affairs
   - Environmental Affairs;     1/91 to 4/95 - Manager, General
     5/1/95                        Electric Company

John A. Nutant - 60             2/94 to present - Vice President
  Vice President                  - Manhattan Customer Service
   - Manhattan                  7/92 to 1/94 - Vice President
     Customer Service;            - Queens Customer Service
     5/27/80                    9/86 - 6/92 - Vice President
                                  - Purchasing
                                7/80 to 8/86 - Vice President -
                                  Environmental Affairs
                                5/80 to 6/80 - Vice President

James P. O'Brien - 48           3/94 to present - Vice President
  Vice President                  - Information Resources
   - Information Resources;         (formerly Systems and
     3/1/94                         Information Processing)
                                6/89 to 2/94 - Assistant Vice
                                  President - Employee Relations

Stephen E. Quinn - 49           9/94 to present - Vice President
  Vice President                  - Nuclear Power
  - Nuclear Power;              8/88 to 8/94 - General Manager
    9/1/94                        - Nuclear Power Generation

Guli R. Rajani - 53             3/96 to present - Vice President
  Vice President                3/91 to 2/96 - Managing Director,
   3/1/96                         Walsh, Greenwood & Company

Edwin W. Scott - 57             6/89 to present - Vice President
  Vice President and Deputy       and Deputy General Counsel
   General Counsel;             
    6/1/89                       
                                
<PAGE>
<PAGE>                         - 48-

                                Business Experience
Name, Age, Positions and        During the Past Five Years
Offices with the Company        or Since Becoming an
and Date First Became an        Executive Officer,
Executive Officer               If Longer

Minto L. Soares - 59            6/91 to present - Vice President
  Vice President                  - Bronx Customer Service
   - Bronx Customer Service;    11/88 to 5/91 - Plant Manager
     6/1/91                      

Alfred R. Wassler - 51          3/94 to present - Vice President
  Vice President                  - Purchasing, Transportation
   - Purchasing, Trans-             and Stores
     portation and Stores;      7/92 to 2/94 - Vice President     
     8/15/80                      - Purchasing
                                8/80 to 6/92 - Treasurer

<PAGE>
<PAGE>                         - 49 -
                                PART II

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

The Company's Common Stock ($2.50 par value) is the only class of
common equity of the Company.  The Common Stock is traded on the
New York, Chicago and Pacific Stock Exchanges.

<TABLE>
MARKET PRICE RANGE IN CONSOLIDATED REPORTING SYSTEM AND DIVIDENDS PAID ON COMMON STOCK
                                          1995                              1994
                               ------------------------------     ----------------------------
                                                  Dividends                          Dividends
                                  High      Low      Paid          High       Low       Paid
----------------------------------------------------------------------------------------------
<S>                            <C>        <C>        <C>           <C>        <C>        <C> 
1st Quarter                    $28-7/8    $25-1/2     $.51          $32-3/8    $28-3/8    $.50        
2nd Quarter                     30-7/8     27         .51           31-3/8     25-3/4     .50        
3rd Quarter                     30-5/8     27-7/8     .51           29-7/8     23         .50        
4th Quarter                     32-1/4     28-3/8     .51           27-1/8     24-1/8     .50        

As of January 31, 1996 there were 151,324 holders of record of common stock.                    
===============================================================================================
</TABLE>

On January 23, 1996, the Board of Trustees of the Company
declared a quarterly dividend of 52 cents per share of Common
Stock which was paid on March 15, 1996 to holders of record on
February 14, 1996.

ITEM 6.  SELECTED FINANCIAL DATA

<TABLE>
===============================================================================================
Year Ended December 31 (Millions of Dollars)   1995       1994       1993       1992       1991
-----------------------------------------------------------------------------------------------
<S>                                       <C>        <C>        <C>        <C>        <C>
Operating revenues                        $ 6,536.9  $ 6,373.1  $ 6,265.4  $ 5,932.9  $ 5,873.1  
Fuel                                          504.1      567.8      605.2      710.3      879.4    
Purchased power                             1,107.2      787.5      812.6      606.8      561.2    
Gas purchased for resale                      259.8      341.2      289.7      245.2      223.4    
Operating income                            1,041.4    1,036.2      951.1      880.4      813.1    
Net income for common stock                   688.3      698.7      622.9      567.7      530.1    
Total assets                               13,949.9*  13,728.4*  13,257.4*  11,596.1   11,107.9   
Long-term obligations
  Long-term debt                            3,917.2    4,030.5    3,643.9    3,493.6    3,364.8   
  Capitalized leases                           45.3       47.8       50.4       52.9       55.5   
  Preferred stock subject to
    mandatory redemption                      100.0      100.0      100.0      100.0       41.3   
Common shareholders' equity                 5,522.7    5,313.0    5,068.5    4,886.9    4,608.3   
-----------------------------------------------------------------------------------------------
Per common share:                                                                             
  Net income                                  $2.93      $2.98      $2.66      $2.46      $2.32   
  Cash dividends                              $2.04      $2.00      $1.94      $1.90      $1.86   
-----------------------------------------------------------------------------------------------
Average common shares                                                                         
  outstanding (millions)                      234.9      234.8      234.0      231.1      228.3   
===============================================================================================
*Includes $1,042.3 million, $1,106.0 million and $1,150.6 million for 1995, 1994 and 1993,
 respectively, of Regulatory Assets attributable to the adoption of SFAS 109.  Equal amounts
 of Accumulated Deferred Federal Income Tax have been established. See Notes A and H to the
 financial statements in Item 8.
</TABLE>
<PAGE>
<PAGE>                         - 50 -

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

LIQUIDITY AND CAPITAL RESOURCES

SOURCES OF LIQUIDITY  Cash and temporary cash investments were
$342.3 million at December 31, 1995 compared with $245.2 million
at December 31, 1994 and $36.8 million at December 31, 1993. The
Company's cash balances reflect, among other things, the timing
and amounts of external financing. The Company's cash
requirements are subject to substantial fluctuations during the
year due to seasonal variations in cash flow and peak in January
and July of each year when the semi-annual payments of New York
City property taxes are due. In July 1995 the Company issued $100
million of 6 5/8% 10-year debentures. The cash balance at
December 31, 1995 was used on January 2, 1996 for redemption at
maturity of the $100 million 5% Series CC mortgage bonds and for
a $224 million semi-annual New York City property tax payment.

     In the first quarter of 1994 pursuant to its amended
dividend reinvestment plan, the Company issued 478,016 shares of
common stock for $14.7 million. The Company amended the plan in
1993 to permit, at the option of the Company, the use of new
shares or outstanding shares purchased in the market.

     In February 1994 the Company issued $150 million of 35-year
debentures. In July 1994 the Company issued $150 million of
five-year floating-rate debentures, the interest rate on which is
reset quarterly. In December 1994 the Company issued $100 million
of 35-year tax-exempt debt through the New York State Energy
Research and Development Authority (NYSERDA).

     In April 1993 the Company issued $101 million of 35-year
tax-exempt debt through NYSERDA. The Company issued 373,227
shares of common stock in December 1993 for $11.9 million
pursuant to the Company's amended dividend reinvestment plan.

     In June 1993 the Company issued $380 million of 30-year
debentures of which approximately $80 million was used to meet
1993 capital requirements and the balance was used to retire
higher cost debt securities.

<PAGE>
<PAGE>                       - 51 -  

Advance Refundings. Since 1992 the Company has taken the
opportunity of generally declining interest rates to reduce costs
by redeeming outstanding securities in advance of maturity dates
and replacing them with new securities bearing lower interest or
dividend rates. In August 1995 the Company issued $128.3 million
of 25-year 6.10% tax-exempt debt through NYSERDA, the proceeds of
which were used to redeem a like amount of outstanding 9%
tax-exempt debt. In December 1995 the Company redeemed, in
advance of maturity, $27.4 million of 9.70% Series 1990A
debentures representing the balance of this issue outstanding.
Excluding the preferred stock transactions discussed below,
approximately $1.9 billion of securities have been refunded,
producing aggregate first-year savings in interest and preferred
dividends of about $25 million, with continued savings in
subsequent years.

Tender Offer. In January 1996 the Company commenced a tender
offer for certain series of its preferred stock. Shareholders
tendered approximately $227 million of such preferred stock
pursuant to the offer, which expired on February 27, 1996. The
Company expects to call $90 million of its other preferred stock
for redemption and to issue subordinated debentures (interest
payments on which, unlike preferred stock dividends, are tax
deductible) to fund the purchase of the tendered stock and the
redemptions. The Company's current expectation is that these
transactions will produce present value revenue-equivalent
savings of approximately $42 million. Under generally accepted
accounting principles, the net gain realized from these
transactions as a result of acquiring preferred stock below its
book value will be included in the calculation of period earnings
per share, but not in net income. In accordance with an order of
the New York State Public Service Commission (PSC), the Company,
consistent with its objective of reducing potentially strandable
costs (discussed below), will apply the net gain, which is
presently estimated to be approximately $14 million, to reduce
net utility plant by an additional provision for depreciation.
While 1996 net income will be reduced by the amount of the
additional provision for depreciation, due to the treatment of
the net gain, earnings per share will be unaffected.

     In 1994 and 1993 the Company borrowed from banks for short
periods; in 1995 there were no short-term borrowings. For 1996
the Company has arranged for bank credit lines amounting to $150
million. Borrowings thereunder would bear interest at prevailing
market rates.

     Customer accounts receivable, less allowance for
uncollectible accounts, amounted to $497.2 million, $440.5
million and $459.3 million at December 31, 1995, 1994 and 1993,
respectively. In terms of equivalent days of revenue outstanding,
these amounts represented 27.6, 27.1 and 27.6 days, respectively.
<PAGE>
<PAGE>                       - 52 -

     Regulatory accounts receivable at December 31, 1995 amounted
to a net credit to be refunded to customers of $6.5 million. Net
regulatory accounts receivable recoverable from customers
amounted to $26.3 million and $97.1 million at December 31, 1994
and 1993, respectively. See Note A to the financial statements.

     The following is a summary of the balances and activity in
regulatory accounts receivable in 1995:

<TABLE>
<CAPTION>
                                                                1995
                                  Balance                    Recoveries      Balance
                                 Dec. 31,         1995          from         Dec. 31,
(Millions of Dollars)              1994*       Accruals*    Customers**       1995*
-------------------------------------------------------------------------------------
<S>                              <C>          <C>          <C>              <C>
ERAM/Modified ERAM                 $(56.4)      $(35.3)        $ 54.0       $(37.7)
Electric Incentives
     Enlightened Energy
       program                       70.1         32.7          (83.1)        19.7
     Customer service                 6.7          5.7           (8.4)         4.0
     Fuel and purchased power         5.9         19.2          (23.2)         1.9
Gas Incentives
     System improvement                --          6.1           (1.5)         4.6
     Customer service                  --          1.3           (0.3)         1.0
                                 ----------------------------------------------------
Total                              $ 26.3       $ 29.7         $(62.5)      $ (6.5)
-------------------------------------------------------------------------------------
</TABLE>
*   Negative amounts are refundable; positive amounts
    recoverable.
**  Negative amounts were recovered; positive amounts refunded.

     The components of the balance in regulatory accounts
receivable at December 31, 1995 will be refunded to or recovered
from customers during 1996 and 1997 as discussed in Note A to the
financial statements. The incentives are discussed below under
"1992 Electric Rate Agreement," "1995 Electric Rate Agreement"
and "Gas and Steam Rate Agreements."

     Deferred charges for Enlightened Energy (demand side
management) program costs amounted to $144.3 million, $170.2
million and $140.1 million at December 31, 1995, 1994 and 1993,
respectively. These costs are being recovered in rates, as
discussed below under the "1992 Electric Rate Agreement" and
"1995 Electric Rate Agreement."

     The Company's earnings include an allowance for funds used
during construction which, as a percent of net income for common
stock, was 0.8 percent in 1995 and 1.7 percent in 1994 and 1993.

<PAGE>
<PAGE>                       - 53 -

     Interest coverage on the SEC book basis was 4.20, 4.58 and
4.19 times for 1995, 1994 and 1993, respectively. The decline in
interest coverage in 1995 was due to lower earnings and higher
interest charges. The improvement in interest coverage in 1994
was due to debt refundings and increased earnings. The Company's
interest coverage continues to be high compared with the electric
utility industry generally.

     The Company's senior debt (first mortgage bonds) is rated
Aa3, A+ and AA- by Moody's Investors Service (Moody's), Standard
& Poor's (S&P) and Duff and Phelps, Inc., respectively. Moody's
and S&P revised their ratings during 1995 from Aa2 and AA-,
respectively. Major factors for the revision were the uncertain
implications of New York's transition towards a more
market-oriented energy industry and the Company's obligations
under contracts with independent power producers (IPPs) (see
"Electric Capacity Resources" below and Note G to the financial
statements). The Company has not issued first mortgage bonds
since 1974; as of December 31, 1995 $175 million of first
mortgage bonds were outstanding, all of which mature in 1996. The
Company's unsecured debt securities (debentures and tax-exempt
debt) are rated A1, A+ and A+ by Moody's, S&P and Duff and
Phelps, Inc., respectively.

     Cash flows from operating activities for years 1993 through
1995 were as follows:

<TABLE>
<CAPTION>
 
(Millions of Dollars)                             1995    1994    1993
------------------------------------------------------------------------
<S>                                               <C>     <C>     <C>
Net cash flows from operating activities          $1,276  $1,250  $1,025
Less: Dividends on common and preferred stock        515     505     490
                                                  ----------------------
Net after dividends                               $  761  $  745  $  535
------------------------------------------------------------------------
</TABLE>

     Net cash flows in 1995 were favorably affected by incentive
billings of $116.5 million, offset by the refund to customers of
$54.0 million of revenues under the ERAM. Net cash flows in 1994
were favorably affected by incentive billings of $92.3 million,
ERAM billings of $28.9 million and labor productivity
improvements resulting in costs estimated to be approximately $51
million less than reflected in rates. See the table above for
balances in regulatory accounts receivable at December 31, 1995
to be refunded to or recovered from customers in future periods.

<PAGE>
<PAGE>                       - 54-
CAPITAL REQUIREMENTS  The following table compares the Company's
capital requirements for the years 1993 through 1995 and
estimated amounts for 1996 and 1997:

<TABLE>
<CAPTION>
(Millions of Dollars)             1997*   1996*   1995    1994    1993
-----------------------------------------------  ----------------------
<S>                              <C>     <C>     <C>     <C>     <C>
Construction expenditures        $ 671   $ 678   $ 693   $  758  $  789
Enlightened Energy program
 costs less recoveries/(a)/        (33)    (15)    (26)      30      59
Power contract termination
 costs - net/(a)/                  (39)    (31)    (55)      62      68
Nuclear decommissioning
 trust/(a)//(b)/                    21      21      19       15      19
Nuclear fuel                        44      24      13       47      14
Investment in gas marketing
 subsidiary                         10      10       2        7       1
                                 --------------  ----------------------
Subtotal                           674     687     646      919     950
Retirement of long-term debt
 and preferred stock/(c)/          106     184      11      134     178
                                 --------------  ----------------------
Total                            $ 780   $ 871   $ 657   $1,053  $1,128
-----------------------------------------------------------------------
</TABLE>
/(a)/  See discussion below of electric rate agreements.
/(b)/  See Note A to the financial statements for discussion of nuclear
       decommissioning costs.
/(c)/  Does not include refundings in advance of maturity, nor the preferred
       stock refunding in 1996 discussed above. For details of securities
       maturing after 1997, see Note B to the financial statements.

     Capital requirements shown above for 1995 were met from
internally generated funds. The Company expects to meet these
capital requirements for 1996 and 1997, including $290 million of
maturing securities, from cash balances, internally generated
funds and external financings of about $150 million, which would
likely be debt issues.* In 1996 and 1997 the Company may, from
time to time, make short-term borrowings.

ELECTRIC CAPACITY RESOURCES  Electric peak load in the Company's
service area, adjusted for historical design weather conditions,
grew by 150 MW (1.4 percent) in 1995. The growth was due
primarily to unusually high use of existing and new air
conditioners by customers during the exceptionally humid summer.
The growth in peak load has been moderated by the Company's
Enlightened Energy program, introduced in 1990, which helps the
Company's customers purchase and install energy-efficient
equipment and encourages the efficient use of energy resources.
This program continues to be modified for future years, based on
the Company's experience to date, so as to obtain energy
efficiency benefits at lower program costs.

________
* These are forward-looking statements, and as such are subject
to the same considerations discussed under "Five-Year Forecast"
in Item 1.
<PAGE>
<PAGE>                       - 55 -

     In response to federal and state regulatory policies and
requirements for utilities to contract with IPPs, the Company by
December 1992 had entered into contracts for the supply of
substantial capacity from facilities of IPPs. Plants with 1,798
MW of such capacity are in commercial operation, and the related
charges are reflected in the Company's rates. Approximately 186
MW of additional capacity is expected to be in operation and in
rates in 1996. Thereafter, additional capacity totalling about 70
MW is expected.

     After 1992 estimates of future market prices for power
decreased significantly as excess generating capacity developed
in the Northeast. During 1993 and 1994, the Company entered into
agreements to terminate IPP contracts involving approximately 720
MW at a cost of $211 million (exclusive of interest) to be paid
over a period of several years. These costs (including interest)
are already reflected in rates. See "1995 Electric Rate
Agreement" below.

     The Company's current resource plans, which reflect the
uncertainty as to the future industry structure in New York, do
not include the addition of long-term capacity resources to its
electric system during the next 20 years, other than the IPPs
discussed above.*

COMPETITION  No federal or New York State law presently requires
the Company to permit other sellers of electricity to use the
Company's facilities to make sales to the Company's retail
customers in New York City and Westchester County. However, in
recent years, federal and New York State legislation have
promoted the development of non-utility electric generating
capacity and competition at the wholesale level for electric
capacity and energy sales. A number of states, including New
York, are now considering whether to require electric utilities
to deliver electricity from other sellers directly to electricity
consumers, referred to as "retail wheeling."

Retail Wheeling.  The most likely targets for retail wheeling are
large industrial customers and, to a lesser extent, governmental
customers. Almost all of the Company's customers are residential
or commercial, with sales to industrial customers comprising
about 2 percent of the Company's 1995 electric sales. Most
governmental customers in the Company's service area are, and for
many years have been, served by the New York Power Authority
(NYPA). However, if retail wheeling were permitted, the Company's

________
* This is a forward-looking statement, and as such is subject to
the same considerations discussed under "Five-Year Forecast" in
Item 1.
<PAGE>
<PAGE>                       - 56 -

large-usage commercial customers would also be targets. In any
case, competition would be mitigated by the limited capacity of
the existing transmission facilities for importing power and
energy into the Company's service area. Nevertheless, in a
competitive environment, the Company could be disadvantaged by
the relatively high costs of its generating facilities and the
Company's substantial commitments under its IPP contracts
relative to electric prices in a competitive market. Assuming
performance by the IPPs, the Company is obligated over the terms
of these contracts (which extend for various periods, up to 2034)
to make payments that currently are, and are projected to be,
uneconomic. See Note G to the financial statements.

Competitive Strategy. The Company's strategy for dealing with
competition includes ongoing cost reductions, increased
productivity, pursuit of growth opportunities and strengthening
of customer relations by providing value-added services. Another
major element of the strategy which the Company is promoting with
government and regulators is a "level playing field" on which the
Company could compete without unfair burdens of regulation or
taxation. For example, taxes other than federal income tax
represent 21 cents of every dollar the Company bills customers.

PSC Proceeding.  The PSC is conducting a generic "competitive
opportunities" proceeding to investigate whether and how to
introduce increased competition into the electric utility
industry in the State.

     In June 1995 the PSC adopted principles in this proceeding,
which among other things, state that "The current industry
structure, in which most power plants are vertically integrated
with natural monopoly transmission and distribution, must be
thoroughly examined to ensure that it does not impede or obstruct
development of effective wholesale or retail competition." With
respect to so-called "strandable costs", another principle states
"Utilities should have a reasonable opportunity to recover
prudent and verifiable expenditures and commitments made pursuant
to their legal obligations, consistent with these principles."
The principles also indicate that utilities should take all
practicable measures to mitigate transition costs.

     In October 1995 the investor-owned utility companies of New
York State (including the Company) filed a proposal in this
proceeding that would restructure the State's electric industry
in a carefully planned transition to competition in the wholesale
market where bulk electricity would be bought and sold. Numerous
other parties, including the PSC staff, have submitted proposals
in this proceeding, some of which, if adopted by the PSC, could
adversely affect the Company.
<PAGE>
<PAGE>                       - 57 -

     In December 1995 the administrative law judge (ALJ)
submitted her recommended decision to the PSC. She called for
competition to be implemented at the wholesale level with the
goal of introducing retail access as quickly as possible, but
with caution. The ALJ recommended that utilities be entitled to
present a case showing why it would be reasonable for recovery of
strandable costs to be allowed. She also advocated a "reasonable
opportunity" for consumers to realize savings and pay lower
prices.

     A PSC order in this proceeding is expected in 1996. The
order is not expected to conclude the PSC's review of competition
and related issues. It is not possible to predict the outcome of
the proceeding or its impact upon the Company. See Note A to the
financial statements.

Federal Proceeding. In March 1995 the Federal Energy Regulatory
Commission (FERC) proposed new rules under which the Company and
other electric utilities would be required to file
non-discriminatory open access transmission tariffs that would be
available to wholesale sellers and buyers of electric energy, and
that would also apply to the Company's and other electric
utilities' own wholesale sales of electric energy. As proposed,
the new rules would allow utilities to recover legitimate and
verifiable wholesale stranded costs. FERC would follow this
policy with regard to costs subject to its jurisdiction and urged
the states to follow the same policy with regard to costs subject
to their jurisdictions.

     It is not possible to predict the outcome of this
proceeding. The Company participates in the wholesale electric
market primarily as a buyer, and in this regard should benefit if
rules are adopted which result in lower wholesale prices for its
purchases of electricity for its retail customers.

1992 ELECTRIC RATE AGREEMENT  In April 1992 the PSC approved an
electric rate agreement covering the three-year period April 1,
1992 through March 31, 1995. Under the agreement annual electric
rates were increased by $250.5 million (5.0 percent) in April
1992, by $251.2 million (5.0 percent) in April 1993 and by $55.2
million (1.1 percent) in April 1994. The agreement provided for a
rate of return on common equity of 11.50 percent for the first
rate year and 11.60 percent for the second and third rate years,
based on a common equity ratio of 52 percent. In order to settle
disputed items, including alleged excess earnings in prior years,
the Company's revenue allowance was reduced in each of the three
years by $35 million. For calendar years 1994, 1993 and 1992, the
Company accrued incentives for attaining certain objectives for
the Company's Enlightened Energy program, customer service and 
<PAGE>
<PAGE>                       - 58 -

fuel costs of $116.4 million, $69.6 million and $58.1 million,
respectively, before federal income tax. For each of the three
rate years, the Company's rate of return on electric common
equity, excluding incentives and labor productivity, was below
the thresholds set in the agreement for sharing with customers.

     The agreement introduced a rate-making concept known as the
Electric Revenue Adjustment Mechanism (ERAM). The purpose of the
ERAM was to eliminate the linkage between customers' energy
consumption and Company profits. Under the ERAM rates were based
on annual forecasts of electric sales and sales revenues with
refund to or recovery from customers of any overages or
deficiencies from the forecast in the prior rate year.
Implementation of the ERAM removes from Company earnings all
variations in electric sales from forecasts, including the
effects of year-to-year weather variations, the results of
changes in economic conditions, and the impact of the Enlightened
Energy program. In 1994 the Company set aside $63.7 million to be
refunded to customers for revenue overcollections under the ERAM.
In 1993 and 1992 the Company accrued $10.9 million and $130.1
million, respectively, of additional revenues to be recovered
from customers under the ERAM.

1995 ELECTRIC RATE AGREEMENT  In April 1995 the PSC approved a
three-year electric rate agreement effective April 1, 1995. The
principal features of the agreement are as follows:

Limited Increases in Base Revenues.  There was no increase in
base electric revenues for the first rate year of the agreement
(the twelve months ending March 31, 1996). However, differences
between actual and projected amounts for certain expense items
for each rate year will be reconciled and deferred for refund to
or recovery from customers in subsequent years. These items
include pension and retiree health and life insurance expenses,
costs incurred under IPP contracts, and certain Enlightened
Energy and renewable energy expenses. Property tax differences
will be similarly reconciled and refunded to or recovered from
customers, except that the Company will absorb (or retain) 14
percent of any property tax increase or decrease from the
forecast amounts.

     For the second and third rate years, rates will also be
changed to provide for projected costs in each year of pensions
and retiree health and life insurance, IPP contracts, and the
Enlightened Energy program.  Pension and postretirement benefit
costs will increase substantially in 1996, reflecting the
discount rate and health cost trend rates assumed.  See Notes D
and E to the financial statements.

<PAGE>
<PAGE>                       - 59 -

     Unlike previous multi-year rate agreements, there will be no
increases in rates in the second and third rate years to cover
general escalation, wage and salary increases or carrying costs
on increased utility plant investment. See "Modified ERAM" below
for revenue adjustments to reflect changes in numbers of
customers.

Return on Equity and Equity Ratio. The allowed rate of return on
common equity is 11.1 percent in the first rate year and is to be
adjusted for the second and third rate years by adding or
subtracting one-half of the change in 30-year Treasury bond rates
from a January/February 1995 base, to or from 11.1 percent. The
maximum change in the rate of return from the previous rate year
is 100 basis points (one percent). A preliminary estimate of the
indicated rate of return on equity for the second rate year is
between 10.2 and 10.4 percent. A 52 percent common equity ratio
is assumed throughout the term of the agreement.

     Costs for debt and preferred stock will not be updated from
the levels projected for the first rate year.

Earnings Sharing.  Following each rate year the Company's actual
return on equity will be calculated, using actual capitalization
ratios and debt and preferred stock costs, but excluding any
earnings from the incentives discussed below. The Company will
retain 100 percent of any earnings up to 50 basis points above
the allowed rate of return for that rate year. The Company will
retain 50 percent of earnings exceeding the allowed rate of
return by more than 50 basis points but not more than 150 basis
points and the balance will be deferred for customer benefit. The
Company will retain 25 percent of earnings that exceed the
allowed rate of return by more than 150 basis points; one-third
of the balance will be deferred for customer benefit and
two-thirds will be applied to reduce rate base balances in a
manner to be determined by the Company.

     Due principally to increased productivity, the Company
estimates the actual rate of return on electric common equity,
excluding incentives, for the first rate year will exceed the
sharing threshold of 11.6 percent. As a result, in the fourth
quarter of 1995 the Company recorded a provision for the future
benefit of electric customers of $10.0 million, before federal
income tax.

IPP Termination Costs.  The rate agreement also provides for full
recovery by the Company of all IPP contract termination costs
incurred to date, and permits the Company to petition the PSC to
defer the costs of new IPP contract terminations or
modifications, if any, during the term of the agreement.
<PAGE>
<PAGE>                       - 60 -

Incentive Provisions.  The rate agreement permits the Company to
earn additional incentive amounts, not subject to the earnings
sharing provisions, by attaining certain objectives for the
Company's Enlightened Energy program, fuel costs, and customer
service. While these incentive mechanisms are similar to those
provided under the 1992 electric rate agreement, opportunities
for earning incentives are generally less than under the earlier
agreement. There would also be penalties for failing to achieve
minimum objectives, and there is a penalty-only incentive
mechanism designed to encourage the Company to maintain its high
level of service reliability.

     For calendar year 1995 the Company accrued benefits of $32.7
million (including $17.1 million related to the prior year) and
$5.7 million, before federal income tax, for the Enlightened
Energy incentive and for electric customer service performance,
respectively.

Partial Pass-Through Fuel Adjustment Clause.  The PPFAC incentive
is continued with certain modifications from the 1992 electric
rate agreement. For each rate year of the new agreement there
will be a $35 million cap (previously $30 million) on the maximum
incentive or penalty, with a "sub-cap" (within the $35 million
cap) of $10 million (as previously) for costs associated with
generation from the Company's Indian Point 2 nuclear unit. While
the cap is higher, the targets established for incentive earnings
are generally more difficult than under the prior agreement. For
calendar year 1995 the Company earned $19.2 million, before
federal income tax, under the PPFAC, $6.5 million of which was
earned in the first calendar quarter, under the 1992 agreement.

Modified ERAM.  The agreement continues, in modified form, the
ERAM introduced in the 1992 electric rate agreement. The new
agreement adds to the ERAM a revenue per customer (RPC) mechanism
which excludes from adjustment those variances in the Company's
electric revenues which result from changes in the number of
customers in each electric service classification. In effect, the
Company will retain additional revenues attributable to added
customers, but will bear the revenue shortfall resulting from
lost customers, while other variances from forecast revenues will
be deferred for subsequent recovery from or refund to customers,
and will not affect the Company's earnings. The ERAM and the RPC
mechanism will not apply to delivery service for NYPA.
<PAGE>
<PAGE>                       - 61 -

     At the end of each rate year, the forecast average annual
amount of revenue per customer in each service classification
(the RPC Factor) for that rate year is multiplied by the actual
average number of customers in that classification. The net
difference between that amount and the actual revenues from all
service classifications is deferred for refund to or recovery
from customers in the subsequent rate year; the RPC Factor for
the following rate year will be adjusted to reflect such net
difference. The RPC Factors will also be adjusted in the second
and third rate years to reflect any increase or decrease in
allowed base revenues for reconciliations and projections
discussed above in "Limited Increases in Base Revenues."

     For calendar year 1995 the Company set aside $35.3 million,
before federal income tax, to be refunded to customers for
revenue overcollections under the ERAM, net of $13.3 million
earned under the RPC.

Nuclear Decommissioning Expense.  See Note A to the financial
statements for changes in nuclear decommissioning expense.

Second Rate Year.  In February 1996 the Company filed revisions
to its electric rates to become effective April 1, 1996 for the
second rate year, as required in the agreement. The Company
estimated that there would be no material change in rates. The
matter is pending before the PSC.

Extension of Agreement.  The agreement stipulates that if the
Company abstains from filing for a general electric rate increase
to take effect at the end of the three-year period, the operation
of the rate agreement may be extended beyond March 31, 1998. Any
party to the agreement may file a petition to compel the Company
to justify continuation of the mechanisms, provisions and
formulas beyond March 31, 1998. If the agreement is extended, the
provisions for limited rate changes, adjustment of equity return,
earnings sharing, incentives, and Modified ERAM will continue in
effect until changed by the PSC.

<PAGE>
<PAGE>                       - 62 -

GAS AND STEAM RATE AGREEMENTS  In October 1992 the PSC approved
two-year gas and steam rate agreements which included annual
increases for the first rate year in firm gas and steam rates of
$12.3 million (1.9 percent) and $11.8 million (3.6 percent),
respectively. In September 1993 the PSC granted the Company
permission to increase its firm gas rates for the second rate
year by $21.6 million (2.8 percent). In lieu of a steam rate
increase of $2.1 million for the second rate year, the PSC
authorized the Company to retain certain tax refunds being held
by the Company for refund to steam customers. The gas and steam
rate agreements were premised upon an allowed equity return of
11.6 percent and a common equity ratio of 52 percent of total
capitalization. Earnings above an 11.95 percent return were to be
shared equally with customers. For both rate years, the twelve
months ended September 30, 1993 and 1994, the Company's rate of
return on gas common equity was below the sharing threshold. The
Company's rate of return on steam common equity for the first and
second rate years was above the sharing threshold, and as a
result, the Company recorded a provision for refund to steam
customers of $1.7 million in 1993 and $3.6 million in 1994.

     In October 1994 the PSC approved three-year rate agreements
for gas and steam services. The agreements provide for gas and
steam rate increases in the first rate year, the twelve months
ended September 30, 1995, of $7.7 million (0.9 percent) and $9.9
million (3.0 percent), respectively, and a methodology for rate
changes in the second and third rate years. For both services,
the October 1994 increases reflect a 10.9 percent rate of return
on common equity and a 52 percent common equity ratio. The
agreements contain "excess earnings" provisions giving
stockholders the benefit of 100 percent retention of any earnings
between 10.9 percent and 11.65 percent, and 50 percent sharing
with customers above 11.65 percent. The steam earnings
calculation also excludes the effects of net sales increases
related to abnormal weather, up to a maximum exclusion for
abnormal weather which is the equivalent of 25 basis points in
common equity return per year. The gas agreement contains two
incentive (or penalty) mechanisms (not subject to the "excess
earnings" provisions). In 1995 the Company accrued benefits of
$6.1 million and $1.3 million, before federal income tax, for the
gas system improvement and customer service incentives,
respectively. For the first rate year, the twelve months ended
September 30, 1995, the Company's rates of return on common
equity for gas and steam were below the threshold for sharing.

<PAGE>
<PAGE>                       - 63 -

      Effective October 1, 1995 (the beginning of the second year
of the October 1994 three-year gas and steam rate agreements),
gas and steam rates were increased by $20.9 million (2.5 percent)
and $4.6 million (1.3 percent), respectively. The primary reasons
for the gas rate increase were escalation in certain operation
and maintenance expenses, return and depreciation on higher plant
balances, and recovery of earnings under the incentive provisions
of the agreement. The steam rate increase was primarily to cover
escalation in operation and maintenance expenses, and return and
depreciation on higher plant balances.

CLEAN AIR ACT AMENDMENTS  The Clean Air Act amendments of 1990
impose limits on sulfur dioxide emissions from electric
generating units. Because the Company uses very low sulfur fuel
oil and natural gas as boiler fuels, the sulfur dioxide emissions
limits should not affect the Company's operations. The Company
will incur increased capital and operating costs to meet the
nitrogen oxide emissions limits set by the New York State
Department of Environmental Conservation (DEC) under the
"Reasonably Available Control Technology" (RACT) provisions of
the Clean Air Act. The Company has spent approximately $23
million to comply with the Phase I limitations. The State may
further reduce the nitrogen oxide emissions limits under Phase II
of the RACT program which is expected to take effect in 1999. New
York and nine other member states of the Northeast Ozone
Transport Commission have entered into a Memorandum of
Understanding which calls for the states to adopt more stringent
nitrogen oxide emissions limits for RACT Phases II and III,
effective in 1999 and 2003, respectively. The Company estimates
that the cost of compliance with these phases could approximate
$150 million.

NUCLEAR FUEL DISPOSAL  The Company has a contract with the United
States Department of Energy (DOE) which provides that, in return
for payments being made by the Company to the DOE pursuant to the
contract, the DOE, starting in 1998, will take title to the
Company's spent nuclear fuel, transport it to a federal
repository and store it permanently. Notwithstanding the
contract, the DOE has announced that it is not likely to have an
operating permanent repository before 2015. The DOE has also
taken the position that it is not obligated to begin accepting
the spent fuel until it has an appropriate facility for such
purpose. In June 1994 the Company and a number of other utilities
petitioned the United States Court of Appeals for the District of
Columbia for a declaratory judgment that the DOE is
unconditionally obligated to begin accepting the spent fuel by
1998, an order directing the DOE to implement a program enabling
it to begin acceptance of spent fuel by 1998, and, if warranted, 
<PAGE>
<PAGE>                       - 64 -

appropriate relief for the financial burden to the utilities
resulting from the DOE's delay. The Company estimates that it now
has adequate on-site capacity until 2005 for interim storage of
its spent fuel. Absent regulatory or technological developments
by 2005, the Company expects that it will require additional
on-site or other spent fuel storage facilities. Such additional
facilities would require regulatory approvals. In the event that
the Company is unable to make appropriate arrangements for the
storage of its spent fuel, the Company would be required to
curtail the operation of its Indian Point 2 nuclear unit. See
discussion of decommissioning in Note A to the financial
statements.

SUPERFUND AND ASBESTOS CLAIMS AND OTHER CONTINGENCIES  Reference
is made to Note F to the financial statements for information
concerning potential liabilities of the Company arising from the
Federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 ("Superfund"), from claims relating to
alleged exposure to asbestos, and from certain other
contingencies to which the Company is subject.

COLLECTIVE BARGAINING CONTRACT  The Company's four-year
collective bargaining contract with Local No. 1-2, Utility
Workers' Union of America, which represents 66% of the Company's
employees, expires in June 1996.

IMPACT OF INFLATION  The Company is affected by the decline in
the purchasing power of the dollar caused by inflation.
Regulation permits the Company to recover through depreciation
only the historical cost of its plant assets even though in an
inflationary economy the cost to replace the assets upon their
retirement will substantially exceed historical cost. However,
this is partially offset by the repayment of the Company's
long-term debt in dollars of lesser value than the dollars
originally borrowed.
<PAGE>
<PAGE>                       - 65 -

RESULTS OF OPERATIONS

     Earnings per share were $2.93 in 1995, $2.98 in 1994 and
$2.66 in 1993. The average number of common shares outstanding
for 1995, 1994 and 1993 was 234.9 million, 234.8 million and
234.0 million, respectively.

Earnings for 1995, 1994 and 1993 reflect electric, gas and steam
rate increases, and other provisions of the electric, gas and
steam rate agreements discussed above.

OPERATING REVENUES AND FUEL COSTS  Operating revenues in 1995 and
1994 increased from the prior year by $163.8 million and by
$107.7 million, respectively. The principal increases and
decreases in revenue were:

<TABLE>
<CAPTION>
                                 Increase (Decrease)
                                 --------------------
                                    1995      1994
(Millions of Dollars)            Over 1994  Over 1993
-----------------------------------------------------
<S>                              <C>        <C>
Electric, gas and steam
 rate changes                     $ 29.3    $ 115.8
Fuel rider billings*                22.4     (143.3)
Sales volume changes
  Electric**                        41.4       56.3
  Gas                              (11.7)      26.1
  Steam                            (13.9)      14.4
Gas weather normalization            5.9       (5.6)
Electric:
  ERAM/Modified ERAM
   accruals                         28.4      (74.7)
  Recoveries of prior rate
   year ERAM accruals               83.1       75.9
  Rate refund provision            (10.0)        --
  Off-system sales                  12.5       19.8
Other                              (23.6)      23.0
                                 --------------------
Total                             $163.8    $ 107.7
-----------------------------------------------------
</TABLE>
*    Excludes costs of fuel, purchased power and gas purchased
     for resale reflected in base rates.
**   Includes Con Edison direct customers and delivery service
     for NYPA and municipal agencies.

<PAGE>
<PAGE>                       - 66 -

     The increase in fuel billings in 1995 reflects higher unit
costs of purchased power, offset by lower cost of gas per therm.
The decrease in fuel billings in 1994 reflects decreases in the
unit costs of both purchased power and fuel used to produce
electricity. The cost of gas per therm was 20.2 percent lower in
1995 than in 1994 and was 10.4 percent lower in 1994 than in
1993.

     Electric fuel costs decreased $56.1 million in 1995 largely
because of the Company's increased power purchases and consequent
lower generation; steam fuel costs decreased $7.6 million in 1995
due to lower sendout and lower unit cost of fuel. Electric fuel
costs in 1995 and 1994 were affected by the greater availability
in 1994 than in 1995 of lower-cost nuclear generation from the
Company's Indian Point 2 unit. During 1995 Indian Point 2
underwent a scheduled refueling and maintenance outage and the
unit's low cost generation was, therefore, unavailable for part
of the year. During 1995 the Company purchased 59 percent of its
total electric energy requirements, compared with 51 percent in
1994. Reflecting this increase, including increased purchases of
the relatively high cost power that the Company is required to
pay for under its IPP contracts, purchased power costs increased
by $319.8 million over the 1994 period. Gas purchased for resale
decreased $81.4 million in 1995, reflecting the lower unit cost
of purchased gas, offset by higher sendout.

     Electricity sales volume in the Company's service territory
increased 0.7 percent in 1995 and 2.0 percent in 1994. Gas sales
volume to firm customers decreased 2.8 percent in 1995 and
increased 3.9 percent in 1994. Transportation of customer-owned
gas increased 65.3 percent in 1995 and decreased 12.1 percent in
1994, primarily due to variations in the volume of gas
transported for NYPA's use as boiler fuel at its Poletti unit.
Steam sales volume decreased 4.1 percent in 1995 and increased
4.4 percent in 1994.

     The Company's electricity, gas and steam sales vary
seasonally in response to weather. Electric peak load occurs in
the summer, while gas and steam sales peak in the winter. After
adjusting for variations, principally weather and billing days,
in each period, electricity sales volume increased 1.2 percent in
1995 and 1.5 percent in 1994. Similarly adjusted, gas sales
volume to firm customers increased 0.1 percent in 1995 and 1.6
percent in 1994, and steam sales volume decreased 1.9 percent in
1995 and increased 0.6 percent in 1994. Weather-adjusted sales
represent the Company's estimate of the sales that would have
been made if historical average weather conditions had prevailed.

<PAGE>
<PAGE>                       - 67 -

     Off-system electricity sales increased to 5,035 millions of
kilowatthours (kWhrs) in 1995 compared with 1,785 millions of
kWhrs in 1994. The increase in 1995 in such sales was due largely
to arrangements in which the Company produces electricity for
others using gas they provide as fuel. The Company has purchased
a substantial portion of this electricity for sale to its own
customers.

OTHER OPERATIONS AND MAINTENANCE EXPENSES  Other operations and
maintenance expenses were unchanged in 1995 and decreased 1.5
percent in 1994. For 1995 lower administrative and general
expenses and production expenses at fossil generating stations
were offset in part by higher amortization of previously deferred
Enlightened Energy program costs and higher production expenses
related to the refueling and maintenance outage of the Indian
Point 2 nuclear unit in 1995. For 1994 the decrease reflects
lower production expenses, principally due to the refueling and
maintenance outage of the Indian Point 2 nuclear unit in 1993;
there was no outage in 1994. The decrease was offset in part by
costs in connection with the settlement of an environmental
proceeding (discussed below) and higher health insurance costs.

     During 1995 the Company accrued $10 million for additional
environmental investigation and site remediation costs pursuant
to a 1994 settlement of a DEC civil administrative proceeding
against the Company and $5 million for two Superfund sites. In
1994, pursuant to the DEC settlement, the Company paid a $9
million penalty and contributed $5 million to an environmental
projects fund. The penalty was charged to miscellaneous income
deductions ($2 million in 1994 and $7 million in prior years).
The payment to the environmental projects fund was charged to
operations and maintenance expenses in 1994. In addition the
Company accrued $11.5 million during 1994 for environmental
investigation and site remediation costs. See Note F to the
financial statements for additional information about the
settlement.

<PAGE>
<PAGE>                       - 68 -

TAXES, OTHER THAN FEDERAL INCOME TAX  At $1.1 billion, taxes
other than federal income tax remain one of the Company's largest
operating expenses. The principal components and variations in
operating taxes were:

<TABLE>
<CAPTION>
                                          Increase (Decrease)
                                         ---------------------
                                           1995        1994
(Millions of Dollars)           1995     Over 1994   Over 1993
--------------------------------------------------------------
<S>                          <C>         <C>         <C> 
Property taxes               $  534.0      $ (5.4)     $(36.8)
State and local taxes
  on revenues                   460.3        (2.2)       (6.3)
Payroll taxes                    58.2          .4         (.2)
Other taxes                      67.7         (.3)       11.7
                             ---------------------------------
Total                        $1,120.2*      $(7.5)     $(31.6)
--------------------------------------------------------------
</TABLE>
* Including sales taxes on customers' bills, total taxes other
  than federal income tax billed to customers in 1995 were
  $1,413.8 million.

The reductions in property taxes in 1995 and 1994 reflect
decreases in the share of total New York City property taxes
borne by the Company. Under the terms of the current electric,
gas and steam rate agreements most of the difference between
property taxes included in rates and actual property taxes is
being deferred for future recovery from or refund to customers.

OTHER INCOME  Other income increased $8.2 million in 1995 and
decreased $2.3 million in 1994. For 1995 the increase reflects
higher interest on temporary cash investments and for 1994 the
decrease reflects lower interest income accrued on ERAM revenue
deferrals under the 1992 electric rate agreement.

NET INTEREST CHARGES  Interest on long-term debt increased $12.9
million in 1995 and $7.3 million in 1994 principally as a result
of new debt issues, offset to a large extent in 1994 by the
effect of debt refundings. Other interest increased $9.1 million
in 1995 principally as a result of a higher customer deposit rate
and interest associated with certain tax settlements.

FEDERAL INCOME TAX  Federal income tax decreased $41.0 million in
1995 and increased $73.6 million in 1994 reflecting the changes
each year in income before tax and in tax credits. See Note H to
the financial statements.

February 27, 1996




<PAGE>
<PAGE>                         - 69 -


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. Financial Statements

                                                         Page
    Index to Financial Statements                       Number

    Report of Independent Accountants                     71

    Consolidated Balance Sheet at December 31, 1995     72-73
    and 1994

    Consolidated Income Statement for the years           74
    December 31, 1995, 1994 and 1993

    Consolidated Statement of Cash Flows for the          75
    years ended December 31, 1995, 1994 and 1993

    Consolidated Statement of Capitalization at         76-77
    December 31, 1995 and 1994

    Consolidated Statement of Retained Earnings           78
    for the years ended December 31, 1995, 1994 and 1993

    Notes to Consolidated Financial Statements          79-99

    The following Schedule is filed as a "Financial Statement
    Schedule" pursuant to Item 14 of this report:

    Schedule VIII - Valuation and Qualifying Accounts  100-102

    All other schedules are omitted because they are not
    applicable or the required information is shown in the
    financial statements or notes thereto.

    Separate financial statements of subsidiaries, not
    consolidated, have been omitted because, if considered in the
    aggregate, they would not constitute a significant
    subsidiary.
<PAGE>
<PAGE>                         - 70 -


B. Supplementary Financial Information

   Selected Quarterly Financial Data for the years ended December
   31, 1995 and 1994 (Unaudited)

<TABLE>
                                                        First     Second       Third     Fourth
1995 (Millions of Dollars)                            Quarter    Quarter     Quarter    Quarter
-----------------------------------------------------------------------------------------------
<S>                                                 <C>        <C>         <C>        <C>
Operating revenues                                   $1,668.8   $1,459.8    $1,879.9   $1,528.4
Operating income                                        280.0      156.0       412.8      192.6
Net income                                              201.1       76.4       333.3      113.1
Net income for common stock                             192.2       67.5       324.4      104.2
Earnings per common share                               $ .82      $ .29       $1.38      $ .44
===============================================================================================
</TABLE>

<TABLE>
                                                        First     Second       Third     Fourth
1994 (Millions of Dollars)                            Quarter    Quarter     Quarter    Quarter
-----------------------------------------------------------------------------------------------
<S>                                                  <C>        <C>         <C>        <C>
Operating revenues                                   $1,697.8   $1,392.1    $1,822.0   $1,461.2
Operating income                                        265.1      158.0       418.4      194.7
Net income                                              189.3       87.2       339.9      117.9
Net income for common stock                             180.4       78.3       331.0      109.0
Earnings per common share                               $ .77      $ .33       $1.41      $ .47
-----------------------------------------------------------------------------------------------
</TABLE>

In the opinion of the Company these quarterly amounts include all
adjustments, consisting only of normal recurring accruals,
necessary for a fair presentation.
<PAGE>
<PAGE>                         - 71 -

                   Report of Independent Accountants


To the Board of Trustees and Stockholders of
Consolidated Edison Company of New York, Inc.

In our opinion, the consolidated financial statements listed
under Item 8.A in the index appearing on page 69 present fairly,
in all material respects, the financial position of Consolidated
Edison Company of New York, Inc. and its 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.  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 of these statements in
accordance with generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement.  An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used
and significant estimates made by management, and evaluating the
overall financial statement presentation.  We believe that our
audits provide a reasonable basis for the opinion expressed
above.


Price Waterhouse LLP

Price Waterhouse LLP
1177 Avenue of the Americas
New York, N.Y.  10036

February 27, 1996
<PAGE>
<PAGE>                                                   - 72 -

CONSOLIDATED BALANCE SHEET
Consolidated Edison Company of New York, Inc.
--------------------------------------------------------------------------------
Assets
--------------------------------------------------------------------------------
At December 31 (Thousands of Dollars)                       1995            1994
--------------------------------------------------------------------------------
Utility plant, at original cost (Notes A and B)
Electric                                             $11,319,622     $10,956,187
Gas                                                    1,537,296       1,437,071
Steam                                                    462,975         430,848
General                                                1,085,795       1,083,705
--------------------------------------------------------------------------------
Total                                                 14,405,688      13,907,811
Less: Accumulated depreciation                         4,036,954       3,828,646
--------------------------------------------------------------------------------
Net                                                   10,368,734      10,079,165
Construction work in progress                            360,457         389,630
Nuclear fuel assemblies and components, less
 accumulated amortization                                 85,212          92,413
--------------------------------------------------------------------------------
Net utility plant                                     10,814,403      10,561,208
================================================================================
Current assets
Cash and temporary cash investments (Note A)             342,292         245,221
Accounts receivable--customers, less allowance for
 uncollectible accounts of $21,600 in 1995 and 1994      497,215         440,496
Other receivables                                         45,558          61,853
Regulatory accounts receivable (Note A)                   (6,481)         26,346
Fuel, at average cost                                     40,506          50,883
Gas in storage, at average cost                           26,452          50,698
Materials and supplies, at average cost                  221,026         229,744
Prepayments                                               66,148          56,283
Other current assets                                      15,126          13,262
--------------------------------------------------------------------------------
Total current assets                                   1,247,842       1,174,786
================================================================================
Investments and nonutility property                      145,646         111,523
================================================================================
Deferred charges (Note A)
Enlightened Energy program costs                         144,282         170,201
Unamortized debt expense                                 133,812         138,428
Power contract termination costs                         105,408         180,506
Other deferred charges                                   316,237         285,721
--------------------------------------------------------------------------------
Total deferred charges                                   699,739         774,856
================================================================================
Regulatory asset -- future federal income taxes
 (Notes A and H)                                       1,042,260       1,105,991
================================================================================
Total                                                $13,949,890     $13,728,364
================================================================================
<PAGE>
<PAGE>                                   - 73 -
 
================================================================================
Capitalization and Liabilities
--------------------------------------------------------------------------------
At December 31 (Thousands of Dollars)                       1995            1994
--------------------------------------------------------------------------------
Capitalization (see Consolidated Statement of
 Capitalization)
Common shareholders' equity                         $  5,522,734    $  5,312,997
Preferred stock subject to mandatory redemption
 (Note B)                                                100,000         100,000
Other preferred stock                                    539,917         540,310
Long-term debt                                         3,917,244       4,030,464
--------------------------------------------------------------------------------
Total capitalization                                  10,079,895       9,983,771
================================================================================
Noncurrent liabilities
Obligations under capital leases                          45,250          47,805
Other noncurrent liabilities                              75,907          72,561
--------------------------------------------------------------------------------
Total noncurrent liabilities                             121,157         120,366
================================================================================

Current liabilities
Long-term debt due within one year (Note B)              183,524          10,889
Accounts payable                                         420,852         374,469
Customer deposits                                        158,366         161,455
Accrued taxes                                             24,374           9,821
Accrued interest                                          89,374          84,544
Accrued wages                                             76,459          73,611
Other current liabilities                                168,477         179,611
--------------------------------------------------------------------------------
Total current liabilities                              1,121,426         894,400
================================================================================

Provisions related to future federal income taxes
 and other deferred credits (Notes A and H)
Accumulated deferred federal income tax                2,296,284       2,266,458
Accumulated deferred investment tax credits              181,420         191,524
Other deferred credits                                   149,708         271,845
--------------------------------------------------------------------------------
Total deferred credits                                 2,627,412       2,729,827
================================================================================
Contingencies (Note F)                      
================================================================================
Total                                                $13,949,890     $13,728,364
================================================================================
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE>                                   - 74 -

CONSOLIDATED INCOME STATEMENT
Consolidated Edison Company of New York, Inc.
===============================================================================
Year Ended December 31 (Thousands of Dollars)       1995        1994       1993
---------------------------------------------       ----        ----       ----
Operating revenues (Note A)
Electric                                      $5,389,408  $5,140,472 $5,131,665
Gas                                              813,356     890,107    808,389
Steam                                            334,133     342,507    325,340
-------------------------------------------------------------------------------
Total operating revenues                       6,536,897   6,373,086  6,265,394
===============================================================================
Operating expenses
Fuel                                             504,104     567,764    605,213
Purchased power                                1,107,223     787,455    812,616
Gas purchased for resale                         259,789     341,204    289,708
Other operations                               1,139,732   1,146,094  1,106,966
Maintenance                                      512,102     506,179    570,794
Depreciation and amortization (Note A)           455,776     422,356    403,730
Taxes, other than federal income tax           1,120,232   1,127,691  1,159,283
Federal income tax (Notes A and H)               396,560     438,160    366,020
-------------------------------------------------------------------------------
Total operating expenses                       5,495,518   5,336,903  5,314,330
===============================================================================
Operating income                               1,041,379   1,036,183    951,064
-------------------------------------------------------------------------------
Other income (deductions)
Investment income (Note A)                        16,966      10,601      4,934
Allowance for equity funds used during
 construction (Note A)                             3,763       8,354      7,222
Other income less miscellaneous deductions        (8,149)    (15,201)    (7,565)
Federal income tax (Notes A and H)                (1,060)       (430)     1,010
--------------------------------------------------------------------------------
Total other income                                11,520       3,324      5,601
================================================================================
Income before interest charges                 1,052,899   1,039,507    956,665
--------------------------------------------------------------------------------
Interest on long-term debt                       301,917     289,060    281,756
Other interest                                    28,954      19,853     19,721
Allowance for borrowed funds used during
 construction (Note A)                            (1,822)     (3,676)    (3,334)
--------------------------------------------------------------------------------
Net interest charges                             329,049     305,237    298,143
================================================================================
Net income                                       723,850     734,270    658,522
Preferred stock dividend requirements             35,565      35,587     35,617
-------------------------------------------------------------------------------
Net income for common stock                   $  688,285 $   698,683 $  622,905
================================================================================
Earnings per common share based on average
 number of shares outstanding during each
 year (234,930,301; 234,753,901; and
 233,981,369)                                      $2.93       $2.98      $2.66
================================================================================
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE>                                   - 75 -
CONSOLIDATED STATEMENT OF CASH FLOWS
Consolidated Edison Company of New York, Inc.
<TABLE> 
<CAPTION> 
====================================================================================
Year Ended December 31 (Thousands of Dollars)         1995          1994        1993
<S>                                             <C>           <C>          <C>  
Operating activities
Net income                                      $  723,850    $  734,270   $ 658,522
Principal non-cash charges (credits) to
 income
Depreciation and amortization                      455,776       422,356     403,730
Federal income tax deferred                         69,020        64,090      94,210
Common equity component of allowance for
 funds used during construction                     (3,546)       (7,876)     (6,795)
Other non-cash charges                             (47,555)       65,669     (20,578)
Changes in assets and liabilities
Accounts receivable--customers, less allowance
 for uncollectibles                                (56,719)       18,765     (34,912)
Regulatory accounts receivable                      32,827        70,771      70,814
Materials and supplies, including fuel and gas
 in storage                                         43,341        17,306      60,554
Prepayments, other receivables and other
 current assets                                      4,566        21,317     (32,236)
Enlightened Energy program costs                    25,919       (30,144)    (59,297)
Power contract termination costs                    55,387       (62,376)    (68,380)
Accounts payable                                    46,383       (18,074)     19,007
Other--net                                         (72,791)      (46,175)    (59,374)
------------------------------------------------------------------------------------
Net cash flows from operating activities         1,276,458     1,249,899   1,025,265
====================================================================================
Investing activities including construction
Construction expenditures                         (692,803)     (757,530)   (789,068)
Nuclear fuel expenditures                          (12,840)      (47,071)    (14,092)
Contributions to nuclear decommissioning trust     (18,893)      (14,586)    (19,247)
Common equity component of allowance for
 funds used during construction                      3,546         7,876       6,795
------------------------------------------------------------------------------------
Net cash flows from investing activities
 including construction                           (720,990)     (811,311)   (815,612)
====================================================================================
Financing activities including dividends
Issuance of common stock                                --        14,650      11,881
Issuance of long-term debt                         228,285       400,000   1,378,475
Retirement of long-term debt                       (10,889)     (133,639)   (177,897)
Advance refunding of long-term debt               (155,699)           --  (1,069,732)
Issuance and refunding costs                        (5,269)       (5,988)   (108,562)
Common stock dividends                            (479,262)     (469,561)   (453,902)
Preferred stock dividends                          (35,563)      (35,585)    (35,614)
------------------------------------------------------------------------------------
Net cash flows from financing activities
 including dividends                              (458,397)     (230,123)   (455,351)
====================================================================================
Net increase (decrease) in cash and temporary
 cash investments                                   97,071       208,465    (245,698)
====================================================================================
Cash and temporary cash investments at
 January 1                                         245,221        36,756     282,454
====================================================================================
Cash and temporary cash investments at
 December 31                                   $   342,292   $   245,221  $   36,756
====================================================================================
Supplemental disclosure of cash flow
 information
Cash paid during the period for:
   Interest                                    $   309,953   $   269,839  $  265,475
   Income taxes                                    344,754       385,355     280,122
====================================================================================
</TABLE> 
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE>                                           - 76 -
 
CONSOLIDATED STATEMENT OF CAPITALIZATION
Consolidated Edison Company of New York, Inc.
<TABLE> 
<CAPTION> 
=======================================================================================================
At December 31 (Thousands of Dollars)                                             1995             1994
                       
                                                Shares outstanding
                                      -----------------------------------
                                      December 31, 1995 December 31, 1994
                                      -----------------------------------
<S>                                   <C>               <C>                   <C>           <C>  
Common shareholders' equity (Note B)
Common stock, $2.50 par value,
 authorized 340,000,000 shares              234,956,299       234,905,235     $1,464,305    $1,463,913
Retained earnings                                                              4,097,035     3,888,010
Capital stock expense                                                            (38,606)      (38,926)
------------------------------------------------------------------------------------------------------
Total common shareholders'  equity                                              5,522,734     5,312,997
======================================================================================================
Preferred stock (Note B)
Subject to mandatory redemption
Cumulative Preferred, $100 par value,
   7.20% Series I                               500,000          500,000          50,000        50,000
  6 1/8% Series J                               500,000          500,000          50,000        50,000
------------------------------------------------------------------------------------------------------
Total subject to mandatory redemption                                            100,000       100,000
------------------------------------------------------------------------------------------------------
Other preferred stock
$5 Cumulative Preferred, without par value,
 authorized 1,915,319 shares                  1,915,319        1,915,319         175,000       175,000
Cumulative Preferred, $100 par value,
 authorized 6,000,000 shares*
  5 3/4% Series A                               600,000          600,000          60,000        60,000
  5 1/4% Series B                               750,000          750,000          75,000        75,000
   4.65% Series C                               600,000          600,000          60,000        60,000
   4.65% Series D                               750,000          750,000          75,000        75,000
  5 3/4% Series E                               500,000          500,000          50,000        50,000
   6.20% Series F                               400,000          400,000          40,000        40,000
Cumulative Preference, $100 par value,
 authorized 2,250,000 shares
 6% Convertible Series B                         49,174           53,102           4,917         5,310
------------------------------------------------------------------------------------------------------
Total other preferred stock                                                      539,917       540,310
------------------------------------------------------------------------------------------------------
Total preferred stock                                                        $   639,917   $   640,310
======================================================================================================
</TABLE> 
*Represents total authorized shares of cumulative preferred stock, $100 par
 value, including preferred stock subject to mandatory redemption.
<PAGE>
<PAGE>                                           - 77 -
<TABLE>
<CAPTION>
=======================================================================================================
<S>                                      <C>                  <C>                 <C>              <C>
At December 31 (Thousands of Dollars)                                             1995             1994
Long-term debt (Note B)
Maturity                                 Interest Rate        Series
First and Refunding Mortgage Bonds (open-end mortgage):
1996                                           5%               CC               $ 100,000      $ 100,000
1996                                           5.90             DD                  75,000         75,000
---------------------------------------------------------------------------------------------------------
Total mortgage bonds                                                               175,000        175,000
Debentures:
1997                                           5.30%            1993 E             100,000        100,000
1998                                           6 1/4            1993 A             100,000        100,000
1998                                           5.70             1993 F             100,000        100,000
1999                                           6 1/2            1992 D              75,000         75,000
1999                                           *                1994 B             150,000        150,000
2000                                           7 3/8            1992 A             150,000        150,000
2000                                           7.60             1992 C             125,000        125,000
2001                                           6 1/2            1993 B             150,000        150,000
2002                                           6 5/8            1993 C             150,000        150,000
2003                                           6 3/8            1993 D             150,000        150,000
2004                                           7 5/8            1992 B             150,000        150,000
2005                                           7 3/8            1992 E              75,000         75,000
2005                                           6 5/8            1995 A             100,000             --
2023                                           7 1/2            1993 G             380,000        380,000
2025                                           9.70             1990 A                  --         27,414
2026                                           9 3/8            1991 A              95,329         95,329
2027                                           8.05             1992 F             100,000        100,000
2029                                           7 1/8            1994 A             150,000        150,000
---------------------------------------------------------------------------------------------------------
Total debentures                                                                 2,300,329      2,227,743
---------------------------------------------------------------------------------------------------------
Tax-exempt debt--notes issued to New York State Energy Research and
Development Authority for Facilities Revenue Bonds:
2020                                           9  %             1985 A                --          128,285
2020                                           6.10             1995 A             128,285             --
2020                                           5 1/4            1993 B             127,715        127,715
2021                                           7 1/2            1986 A             150,000        150,000
2022                                           7 1/8            1987 A             100,855        100,855
2022                                           9 1/4            1987 B              29,385         29,385
2022                                           5 3/8            1993 C              19,760         19,760
2024                                           7 3/4            1989 A             150,000        150,000
2024                                           7 3/8            1989 B             100,000        100,000
2024                                           7 1/4            1989 C             150,000        150,000
2025                                           7 1/2            1990 A             150,000        150,000
2026                                           7 1/2            1991 A             128,150        128,150
2027                                           6 3/4            1992 A             100,000        100,000
2027                                           6 3/8            1992 B             100,000        100,000
2028                                           6                1993 A             101,000        101,000
2029                                           7 1/8            1994 A             100,000        100,000
---------------------------------------------------------------------------------------------------------
Total tax-exempt debt                                                            1,635,150      1,635,150
---------------------------------------------------------------------------------------------------------
Other long-term debt:
Liens on purchased gas turbines                                                      13,327        22,779
Other long-term debt                                                                  5,836         9,007
Unamortized debt discount                                                           (28,874)      (28,326)
---------------------------------------------------------------------------------------------------------
Total                                                                             4,100,768     4,041,353
Less: Long-term debt due within one year                                            183,524     10,889
---------------------------------------------------------------------------------------------------------
Total long-term debt                                                              3,917,244     4,030,464
---------------------------------------------------------------------------------------------------------
Total capitalization                                                            $10,079,895    $9,983,771
---------------------------------------------------------------------------------------------------------
</TABLE>
* This rate is reset quarterly. For the fourth quarter of 1995 it was 6.125%.
  The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE>                                           - 78 -

CONSOLIDATED STATEMENT OF RETAINED EARNINGS
Consolidated Edison Company of New York, Inc.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
Year Ended December 31 (Thousands of Dollars)                   1995            1994         1993
----------------------------------------------------------------------------------------------------------
<S>                                                         <C>              <C>           <C>
Balance, January 1                                          $3,888,010       $3,658,886    $3,489,880
Net income for the year                                        723,850          734,270       658,522
----------------------------------------------------------------------------------------------------------
Total                                                        4,611,860        4,393,156     4,148,402
----------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------
Dividends declared on capital stock
Cumulative Preferred, at required annual rates                  35,259           35,259        35,259
Cumulative Preference, 6% Convertible Series B                     304              326           355
Common, $2.04, $2.00 and $1.94 per share                       479,262          469,561       453,902
----------------------------------------------------------------------------------------------------------
Total dividends declared                                       514,825          505,146       489,516
----------------------------------------------------------------------------------------------------------
Balance, December 31                                        $4,097,035       $3,888,010    $3,658,886
----------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these financial statements.

<PAGE>
<PAGE>                       - 79 -

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

-----------------------------------------------------------------
Note A  Summary of Significant Accounting Policies
-----------------------------------------------------------------
Regulation.  The Company is subject to regulation by the New York
Public Service Commission (PSC) and the Federal Energy Regulatory
Commission (FERC). The Company's accounting policies conform to
generally accepted accounting principles, as applied in the case
of regulated public utilities, and to the accounting requirements
and rate-making practices of these regulatory authorities.

    The PSC is conducting a generic "competitive opportunities"
proceeding to investigate whether and how to introduce increased
competition into the electric utility industry in the State. It
is not possible to predict the outcome of the proceeding or its
impact upon the Company. The outcome could adversely affect the
Company's eligibility to apply Statement of Financial Accounting
Standards ("SFAS") No. 71, "Accounting for the Effects of Certain
Types of Regulation," which could then require a material
write-down of assets, the amount of which is not presently
determinable. SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of,"
requires long-lived and certain other assets to be reviewed for
impairment if the carrying amount of an asset may not be
recoverable. SFAS No. 121 also amends SFAS No. 71 to require that
regulatory assets (which include certain deferred charges) be
charged to earnings if such assets are no longer considered
probable of recovery. The Company will implement SFAS No. 121 in
1996. Absent a change in regulation as a result of competition as
discussed above, the Company does not expect that the application
of SFAS No. 121, with respect to either its long-lived assets or
its regulatory assets, will have a material adverse effect on the
Company's financial position and results of operations.

Principles of Consolidation. The accompanying consolidated
financial statements include the accounts of the Company and its
wholly-owned subsidiaries. Intercompany transactions have been
eliminated.

Utility Plant and Depreciation.  The capitalized cost of
additions to utility plant includes indirect costs such as
engineering, supervision, payroll taxes, pensions, other benefits
and an allowance for funds used during construction (AFDC). The
original cost of property, together with removal cost, less
salvage, is charged to accumulated depreciation as property is
retired. The cost of repairs and maintenance is charged to
expense, and the cost of betterments is capitalized.

<PAGE>
<PAGE>                       - 80 -

   Rates used for AFDC include the cost of borrowed funds used
for construction purposes and a reasonable rate on the Company's
own funds when so used, determined in accordance with PSC and
FERC regulations. The AFDC rate was 9.1 percent in 1995, 9.4
percent in 1994 and 9.5 percent in 1993. The rate was compounded
semiannually, and the amounts applicable to borrowed funds were
treated as a reduction of interest charges. 

     The annual charge for depreciation is computed on the
straight-line method for financial statement purposes using rates
based on average lives and net salvage factors, with the
exception of the Indian Point 2 nuclear unit, the Company's share
of the Roseton generating station, certain leaseholds and 
certain general equipment, which are depreciated on a remaining
life amortization method. Depreciation rates averaged
approximately 3.3 percent in 1995, 3.2 percent in 1994 and 3.1
percent in 1993. Depreciation expense includes the amortization
of certain deferred charges authorized by the PSC.

     The Company is a joint owner of two 1,200-megawatt electric
generating stations: (1) Bowline Point, operated by Orange and
Rockland Utilities, Inc. with the Company owning a two-thirds
interest and (2) Roseton, operated by Central Hudson Gas &
Electric Corp. with the Company owning a 40 percent interest.
Central Hudson has the option to acquire the Company's interest
in the Roseton station in 2004. The Company's share of the
investment in these stations at original cost and as included in
its balance sheet at December 31, 1995 and 1994 was:

----------------------------------------------------------------
(Thousands of Dollars)               1995                1994
----------------------------------------------------------------
Bowline Point: Plant in service     $203,360            $196,065
   Construction work in progress       2,340              10,351
Roseton: Plant in service            145,207             141,487
   Construction work in progress       2,089               4,283
-----------------------------------------------------------------

     The Company's share of accumulated depreciation for the
Roseton station at December 31, 1995 and 1994 was $64.8 million
and $61.6 million, respectively. A separate depreciation account
is not maintained for the Company's share of the Bowline Point
station. The Company's share of operating expenses for these 
stations is included in its income statement.

<PAGE>
<PAGE>                       - 81 -

Nuclear Decommissioning.  Depreciation charges include a
provision for decommissioning both the Indian Point 2 and the
retired Indian Point 1 nuclear units. Decommissioning costs are
being accrued ratably over the Indian Point 2 license period
which extends to the year 2013. The Company has been accruing for
the costs of decommissioning within the internal depreciation
reserve since 1975. In 1989 the PSC permitted the Company to
establish an external trust fund for the costs of decommissioning
the nuclear portions of the plants pursuant to NRC regulations.
Accordingly, beginning in 1989 the Company has made contributions
to such a trust. The external trust fund is discussed below under
"Investments" in this Note A.

    Accumulated decommissioning provisions at December 31, 1995
and 1994, which include earnings on funds externally invested,
were as follows:
----------------------------------------------------------------
                                          Amounts Included in
                                        Accumulated Depreciation
                                        ------------------------
(Millions of Dollars)                   1995              1994

-----------------------------------------------------------------
Nuclear                                $134.4            $102.2
Non-Nuclear                              55.3              53.7
                                      ---------------------------
Total                                  $189.7            $155.9
-----------------------------------------------------------------

     Prior to April 1995 the Company was providing annual expense
allowances of $11.7 million and $3.1 million, respectively, for
decommissioning the nuclear and non-nuclear portions of the
plants. These amounts, which were recovered from customers
through billings, were approved by the PSC in the 1992 electric
rate agreement, and were designed to fund decommissioning costs
which had been estimated at approximately $300 million in 1993
dollars. In 1994 a site-specific decommissioning study was
prepared for both the Indian Point 2 and the retired Indian Point
1 nuclear units. Based upon this study, the estimated
decommissioning cost in 1993 dollars is approximately $657
million, of which $252 million is for extended on-site storage of
spent nuclear fuel. Using a 3.25 percent annual escalation
factor, the estimated cost in 2016, the assumed midpoint for
decommissioning expenditures, is approximately $1,372 million.
Under the 1995 electric rate agreement, effective April 1995, the
Company revised the annual decommissioning expense allowance for
the nuclear and non-nuclear portions of the plants to $21.3
million and $1.8 million, respectively, to fund the future
estimated costs of decommissioning. The annual expense allowance
assumes a 6 percent after-tax annual return on fund assets.
<PAGE>
<PAGE>                       - 82 -

     The Financial Accounting Standards Board (FASB) is currently
reviewing the utility industry's accounting treatment of nuclear
and certain other plant decommissioning costs. The FASB has
preliminarily concluded that decommissioning costs should be
accounted for at present value as a liability, with a
corresponding asset in utility plant, rather than as a component
of depreciation. An exposure draft regarding this matter was
issued in February 1996.

Nuclear Fuel.  Nuclear fuel assemblies and components are
amortized to operating expenses based on the quantity of heat
produced for the generation of electricity. Fuel costs also
include a provision for payments to the U.S. Department of Energy
for the future off-site storage of the spent fuel, based on the
kilowatt-hours of electricity generated. Nuclear fuel costs are
recovered in revenues through base rates or through the fuel
adjustment clause.

Leases.  In accordance with SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation," those leases that meet
the criteria for capitalization are capitalized for accounting
purposes. For rate-making purposes, all leases have been treated
as operating leases.

Revenues.  Revenues for electric and steam service are recognized
on a monthly billing cycle basis. Pursuant to the three-year
electric rate agreements, effective April 1, 1992 and 1995,
actual electric net revenues (operating revenues less fuel and
purchased power costs and revenue taxes) are adjusted by accrual
to target levels established under the agreements in accordance
with the electric revenue adjustment mechanism (ERAM). The 1995
agreement introduced the revenue per customer mechanism (RPC)
which modified the ERAM. Under the RPC, revenues are increased
(or decreased) to reflect variations from target levels in the
numbers of customers in the various service classes. Revenues are
also increased (or decreased) each month to reflect incentives
(or penalties) earned for the Enlightened Energy program and for
customer service activities. The agreements provide that the net
regulatory asset (or liability) thus accrued in each rate year is
to be reflected in customers' bills in the following rate year.

     The October 1994 gas rate agreement provides for revenues to
be increased (or decreased) each month to reflect incentives (or
penalties) earned for meeting gas customer service and system
improvement targets.

<PAGE>
<PAGE>                       - 83 -

   In accordance with a PSC rate order, the Company began phasing
in recognition of unbilled gas revenues over a 4 1/4 year period
effective October 1989. Pursuant to the gas rate decision in
October 1991, this recognition of unbilled gas revenues was
modified so as to be fully phased in by September 30, 1994 to the
extent provided in rates.

   Revenues from the fuel adjustment clauses are not recorded
until billed.

Recoverable Fuel Costs.  Fuel and purchased power costs that are
above the levels included in base rates are recoverable under
electric, gas and steam fuel adjustment clauses. If costs fall
below these levels, the difference is credited to customers. For
electric and steam, such costs are deferred until the period in
which they are billed or credited to customers (40 days for
electric, 30 days for steam). For gas, the excess or deficiency
is accumulated for refund or surcharge to customers on an annual
basis.

   Effective April 1992 a partial pass-through fuel adjustment
clause (PPFAC) was implemented with monthly targets for electric
fuel and purchased power costs. The Company retains for
stockholders 30 percent of any savings in actual costs below the
target amount, but must bear 30 percent of any excess of actual
costs over the target. For each rate year of the 1995 electric
rate agreement there is a $35 million cap on the maximum increase
or decrease in fuel billings, with a limit (within the $35
million) of $10 million for costs associated with generation at
the Company's Indian Point 2 nuclear unit.

   The PSC has allowed the Company to recover in rates certain
deferred recoverable fuel costs that were affected by shortening
the billing lag period or changing the cost of fuel in base
rates. If there were any further such revisions, the Company
believes that deferred recoverable fuel costs affected thereby
would be recovered.

<PAGE>
<PAGE>                       - 84 -

Regulatory Accounts Receivable.  Regulatory accounts receivable
at December 31, 1995 amounted to a net credit to be refunded to
customers of $6.5 million, reflecting accruals under the 1992 and
1995 electric rate agreements and 1994 gas rate agreement for
incentives related to the Company's Enlightened Energy program
($19.7 million), for incentives related to electric customer
service activities ($4.0 million), for the amounts to be billed
under the PPFAC ($1.9 million), for incentives related to gas
system improvement ($4.6 million), for incentives related to gas
customer service ($1.0 million) and for net electric sales
revenues in accordance with the ERAM and Modified ERAM (a refund
of $37.7 million). The revenues accrued in a given twelve-month
period under the ERAM and Modified ERAM and for incentives
related to the Enlightened Energy program, electric customer
service activities and the Company's gas business are being
recovered from or refunded to customers over an ensuing
twelve-month period. The amounts accrued under the PPFAC are
billed to customers on a monthly basis through the electric fuel
adjustment clause.

Enlightened Energy Program Costs.  In accordance with PSC
directives, the Company defers the costs for its Enlightened
Energy (demand side management) program for future recovery from
ratepayers. Such deferrals amounted to $144.3 million at December
31, 1995 and $170.2 million at December 31, 1994. In accordance
with the 1992 and 1995 electric rate agreements, the Company is
generally recovering its Enlightened Energy program costs over a
five-year period.

Temporary Cash Investments.  Temporary cash investments are
short-term, highly liquid investments which generally have
maturities of three months or less. They are stated at cost which
approximates market. The Company considers temporary cash
investments to be cash equivalents.

Investments.  Investments consist primarily of an external
nuclear decommissioning trust fund. At December 31, 1995 and 1994
the trust fund amounted to $134.4 million and $102.2 million,
respectively. Investments are stated at market. Earnings on the
trust fund are not recognized in income but are included in the
accumulated depreciation reserve. See "Nuclear Decommissioning" 
in this Note A.

Federal Income Tax.  The Company provides for deferred federal
income taxes with respect to certain benefits realized from
depreciation deductions utilized for tax purposes, deferred fuel
accounting, unbilled revenues (electricity, gas and steam)
included in taxable income, deferrals arising from the rate
agreements, and certain other specific items, when approved by
the PSC.
<PAGE>
<PAGE>                       - 85 -

     For rate-making purposes, accumulated deferred federal
income taxes previously collected from customers are deducted
from rate base and amortized or otherwise applied as a reduction
in federal income tax expense in future years. Accumulated
deferred investment tax credits are amortized ratably over the
lives of the related properties and applied as a reduction in
future federal income tax expense.

     In accordance with SFAS 109,  "Accounting for Income Taxes," 
the Company is required to record a deferred income tax liability
for substantially all temporary differences between book and tax
bases of assets and liabilities at current tax rates, including
differences for which deferred taxes have not previously been
provided. For regulated enterprises, a regulatory asset is
recognized for the latter if the criteria of SFAS 71 are met,
that is, it is probable that future revenues will be allowed
sufficient in amount to recover the costs for which deferred
taxes have not previously been provided. The regulatory asset,
stated at the revenue requirement level, amounted to $1,042.3
million and $1,106.0 million at December 31, 1995 and 1994,
respectively. These amounts which are included in accumulated
deferred federal income tax (see Note H), are not reflected in
rate base for rate-making purposes. In 1993 the PSC
issued an interim policy statement proposing accounting
procedures consistent with SFAS 109 and providing assurances that
these future increases in taxes will be recoverable in rates. The
final policy statement is not expected to differ materially from
the interim policy statement.

     The Company and its subsidiaries file a consolidated federal
income tax return. Income taxes are allocated to each company
based on its taxable income.

Research and Development Costs.  Research and development costs
relating to specific construction projects are capitalized. All
other such costs are charged to operating expenses as incurred.
Research and development costs in 1995, 1994 and 1993, amounting
to $45.0 million, $46.8 million and $48.0 million, respectively,
were charged to operating expenses. No research and development 
costs were capitalized in these years.

Estimates. The accompanying consolidated financial statements
reflect judgments and estimates made in the application of the
above accounting policies.
<PAGE>
<PAGE>                       - 86 -

--------------------------------------------------------------
Note B  Capitalization
--------------------------------------------------------------
Common Stock and Preferred Stock Not Subject to Mandatory
Redemption.  Each share of Series B preference stock is
convertible into 13 shares of common stock at a conversion price
of $7.69 per share. During 1995, 1994 and 1993, 3,928 shares,
4,176 shares and 5,208 shares of Series B preference stock were
converted into 51,064 shares, 54,288 shares and 67,704 shares of
common stock, respectively.

     At December 31, 1995, 639,262 shares of unissued common
stock were reserved for conversion of preference stock. The
preference stock is subordinate to the $5 Cumulative Preferred
Stock and Cumulative Preferred Stock with respect to dividends
and liquidation rights.

     Redemption prices of preferred stock other than Series I and
Series J (in each case, plus accrued dividends) are as follows:
----------------------------------------------------------------
$5 Cumulative Preferred Stock              $105.00
----------------------------------------------------------------
Cumulative Preferred Stock:
                        Series A           $102.00
                        Series B            102.00
                        Series C            101.00
                        Series D            101.00
                        Series E            101.00
                        Series F            102.50
-----------------------------------------------------------------
Cumulative Preference Stock:
   6% Convertible Series B                 $100.00
-----------------------------------------------------------------

Preferred Stock Subject to Mandatory Redemption.  The Company is
required to redeem 25,000 of the Series I shares on May 1 of each
year in the five-year period commencing with the year 2002 and to
redeem the remaining Series I shares on May 1, 2007. The Company
is required to redeem the Series J shares on August 1, 2002. In
each case, the redemption price is $100 per share plus accrued
and unpaid dividends to the redemption date. In addition, the
Company may redeem Series I shares at a redemption price of
$105.04 per share, plus accrued dividends, if redeemed prior to
May 1, 1996 (and thereafter at prices declining annually to $100
per share, plus accrued dividends, after April 30, 2002);
provided, however, that prior to May 1, 1997, the Company may not
redeem any Series I shares with borrowed funds or proceeds from
certain securities issuances having a cost to the Company of less
than 7.20 percent per annum. 
<PAGE>
<PAGE>                       - 87 - 

     Neither Series I nor Series J shares may be called for
redemption while dividends are in arrears on outstanding shares
of $5 Cumulative Preferred Stock or Cumulative Preferred Stock.
Nevertheless, the mandatory redemption obligation of the Company
with respect to such shares is cumulative and if the redemption
requirement is in arrears the Company may not purchase or redeem
or pay any dividends on the common stock or any other stock
ranking junior as to dividends or assets to the Cumulative
Preferred Stock, except for payments or distributions in common
stock or such junior stock.

Preferred Stock Refunding.  In January 1996 the Company commenced
a tender offer for all of its preferred stock except for the
Series E and F and the 6% convertible Series B. On February 27,
1996 the tender offer expired (except as to the $5 Cumulative
Preferred for which the offer had been terminated) and the
Company's Board of Trustees authorized the redemption of the
Series E and F. Pursuant to the tender offer, approximately $227
million of preferred stock was tendered. The Company intends to
fund the purchase and the redemption by issuing subordinated
debentures.

Long-Term Debt. Total long-term debt maturing in the period
1996-2000 is as follows:
----------------------------------------
1996                        $183,524,000
1997                         106,256,000
1998                         200,000,000
1999                         225,000,000
2000                         275,000,000
----------------------------------------

     Substantially all properties and franchises of the Company,
other than expressly excepted property, are subject to the liens
securing the Company's First and Refunding Mortgage Bonds and the
mortgage bonds of acquired companies.

-----------------------------------------------------------------
Note C Lines of Credit
-----------------------------------------------------------------
The Company has bank lines of credit for 1996 amounting to $150
million. The credit lines require average compensating balances
of 2.5 percent of the credit lines, with interest on any
borrowings to be at prevailing market rates. There are no legal
restrictions applicable to the Company's cash balances resulting
from its obligation to maintain compensating balances.
<PAGE>
<PAGE>                       - 88 -

----------------------------------------------------------------
Note D Pension Plans
----------------------------------------------------------------
The pension plans for management and bargaining unit employees
cover substantially all employees of the Company and are designed
to comply with the Employee Retirement Income Security Act of
1974 (ERISA). Contributions are made solely by the Company based
on an actuarial valuation, and are not less than the minimum
amount required by ERISA. The Company's policy is to fund the
actuarially computed net pension cost as such cost accrues.
Benefits for management and bargaining unit employees are
generally based on a final five-year average pay formula.

     In accordance with SFAS 87,  "Employers' Accounting for
Pensions," the Company uses the projected unit credit method for
determining pension cost. Pension costs for 1995, 1994 and 1993
amounted to $11.4 million, $38.7 million and $46.8 million,
respectively, of which $8.9 million for 1995, $30.3 million for
1994 and $37.1 million for 1993 was charged to operating expense.
In accordance with SFAS 88,  "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and
for Termination Benefits," as modified by SFAS 71, pension cost
for 1993 included $4.4 million in connection with the special
retirement program discussed below. Pension cost for 1995
includes $2.2 million for the amortization of the special
retirement program regulatory asset also discussed below, and an
actuarially determined credit of $7.3 million representing a
prepayment on one of the plans.

     Effective January 1, 1993 the Company adopted the PSC's
"Statement of Policy and Order Concerning the Accounting and
Ratemaking Treatment for Pensions and Postretirement Benefits
Other Than Pensions" (the PSC Policy). The PSC Policy requires
certain departures from SFAS 87, including actuarial recognition
of investment gains and losses over five years and a 10-year
period for amortization of recognized actuarial gains and losses.

     The Company offered a special retirement program in 1993
providing enhanced pension benefits for those employees who met
certain eligibility requirements and retired within specific time
limits. The incentives offered by the Company fall within the
category of special termination benefits as described in SFAS 88.
The increase in pension obligations as a result of this program
amounted to $33.3 million. In accordance with SFAS 71, the
Company charged the equivalent of the first two years of the
amortization ($4.4 million) to pension expense in 1993 and
established a liability and offsetting regulatory asset for the
$28.9 million allocable to future periods. Under an agreement
with the PSC, the Company is amortizing the remaining liability
over a 13-year period. This is reflected in current rates.

<PAGE>
<PAGE>                       - 89 -

     The components of net periodic pension cost for 1995, 1994
and 1993 were as follows:

-----------------------------------------------------------------
(Millions of Dollars)           1995         1994        1993
-----------------------------------------------------------------
Service cost--benefits earned
  during the period            $ 98.2       $ 103.9      $ 103.2
Interest cost on projected
  benefit obligation            296.7         278.2        252.7
Actual return on plan assets   (865.8)         (3.4)      (500.0)
Unrecognized investment
  gain (loss) deferred          521.6        (322.6)       201.5
Net amortization                (41.5)        (17.4)       (15.0)
                               ----------------------------------
Net periodic pension cost         9.2*         38.7         42.4
                               ----------------------------------
Special retirement program cost    --            --         33.3
Decrease (increase) in 
  regulatory asset                2.2            --        (28.9)
                                ---------------------------------
Net special retirement program
 cost                             2.2            --          4.4
                                ---------------------------------
Total pension cost             $ 11.4       $  38.7      $  46.8
-----------------------------------------------------------------
*  Includes a prepayment credit of $7.3 million.

<PAGE>
<PAGE>                       - 90 -

     The funded status of the pension plans as of  December 31,
1995, 1994 and 1993 was as follows:

-----------------------------------------------------------------
(Millions of Dollars)           1995          1994        1993
-----------------------------------------------------------------
Actuarial present value of
 benefit obligation:
   Vested                     $3,319.2      $2,813.0     $2,731.9
   Nonvested                     267.9         189.6        212.6
                              -----------------------------------
   Accumulated to date         3,587.1       3,002.6      2,944.5
   Effect of projected future
       compensation levels     1,070.3         786.0        841.5
                               ----------------------------------
   Total projected obligation  4,657.4       3,788.6      3,786.0
Plan assets at fair value      4,775.8       4,046.7      4,154.3
                               ----------------------------------
Plan assets less projected
 benefit obligation              118.4        258.1        368.3
Unrecognized net gain           (240.3)      (401.1)      (522.9)
Unrecognized prior service cost*  85.3         93.9        102.5
Unrecognized net transition
 liability at January 1, 1987*    17.2         20.2         23.2
                                ---------------------------------
Accrued pension cost**        $  (19.4)    $  (28.9 )    $ (28.9)
-----------------------------------------------------------------
 *    Being amortized over approximately 15 years.
 **   Accrued liability for special retirement program less
      prepayment credit in 1995.

     To determine the present value of the projected benefit
obligation in 1995, 1994 and 1993, discount rates of 7 percent,
8 percent and 7.5 percent, respectively, were assumed. A weighted
average rate of increase in future compensation levels of 5.8
percent and a long-term rate of return on plan assets of 8.5
percent were assumed for all years.

     The pension plan assets consist primarily of corporate
common stock and bonds, group annuity contracts and debt of the
United States government and its agencies.
<PAGE>
<PAGE>                       - 91 -

-----------------------------------------------------------------
Note E Postretirement Benefits Other Than Pensions (OPEB)
-----------------------------------------------------------------

The Company has a contributory comprehensive hospital, medical
and prescription drug program for all retirees, their dependents
and surviving spouses. The Company also provides life insurance
benefits for approximately 6,400 retired employees. All of the
Company's employees become eligible for these benefits upon
retirement except that the amount of life insurance is limited
and is available only to management employees and to those
bargaining unit employees who participated in the optional
program prior to retirement.  The Company has reserved the right
to amend or terminate these programs.

     The Company adopted the provisions of SFAS 106, "Employers' 
Accounting for Postretirement Benefits Other Than Pensions," 
effective January 1, 1993. It contains specific rules for
determining the cost of postretirement health and life insurance
benefits. These rules require accrual of the obligation for
previously unrecognized retiree benefit cost over a shorter
period than  previous methods.

     The Company's policy is to fund in external trusts the
actuarially determined annual costs for retiree health and life
insurance subject to statutory maximum (and minimum) limits. Rate
allowances that are not funded to an external trust accrue
interest at the pre-tax rate of return. As of December 31, 1993
the Company had accrued $6.9 million in interest on an unfunded
liability of $28.5 million. In 1994 the Company funded both
amounts in addition to $0.9 million of interest accrued in 1994.

     The retiree health and life insurance expense for 1995, 1994
and 1993 was determined in accordance with the PSC Policy (see
Note D) which requires the Company to defer the difference
between the rate allowance for OPEB expense and the OPEB expense
determined in accordance with SFAS 106, amortize the transition
obligation over 20 years and recognize all gains and losses over
a 10-year period in determining the SFAS 106 expense. Current
electric, gas and steam rates reflect the increase in expense
resulting from the adoption of SFAS 106. 

<PAGE>
<PAGE>                       - 92 -

     The cost to the Company for retiree health benefits for
1995, 1994 and 1993 amounted to $65.5 million, $67.1 million and
$66.3 million, respectively, of which $51.6 million for 1995,
$52.7 million for 1994 and $52.5 million for 1993 was charged to
operating expense. The cost of the retiree life insurance plan
for 1995, 1994 and 1993 amounted to $18.0 million, $21.6 million
and $22.3 million, respectively, of which $14.2 million for 1995,
$17.0 million for 1994 and $17.7 million for 1993 was charged to
operating expense.

     The components of postretirement benefit (health and life
insurance) costs for years 1995, 1994 and 1993 were as follows: 

----------------------------------------------------------------
(Millions of Dollars)           1995        1994           1993
----------------------------------------------------------------
Service cost--benefits earned
  during the period           $ 10.7       $11.5           $11.1
Interest cost on accumulated
  postretirement benefit
  obligation                    61.2        56.9            52.2
Actual return on plan assets   (60.8)       (8.4)           (8.5)
Unrecognized investment gain 
  (loss) deferred               40.4        (5.7)            2.9
Amortization of transition
  obligation and unrecognized 
  net loss                      32.0        34.4            30.9
                                ---------------------------------
Net periodic postretirement 
  benefit cost                $ 83.5       $88.7           $88.6
-----------------------------------------------------------------

<PAGE>
<PAGE>                       - 93 -  

     The following table sets forth the program's funded status
at December 31, 1995, 1994 and 1993:

----------------------------------------------------------------
(Millions of Dollars)           1995        1994            1993
-----------------------------------------------------------------
Accumulated postretirement
  benefit obligation:
  Retirees                   $  447.7     $ 413.9         $ 413.2
  Employees eligible to retire  250.7       167.2           144.2
  Employees not eligible to
    retire                      305.6       204.5           221.5
                              -----------------------------------
  Total projected obligation  1,004.0       785.6           778.9
Plan assets at fair value       322.2       219.1           130.8
                              -----------------------------------
Plan assets less accumulated 
postretirement benefit
             obligation       (681.8)      (566.5)        (648.1)
Unrecognized net loss          240.8         11.1           33.4
Unrecognized net transition
 liability at January 1, 1993* 441.0        555.4          586.2
                               ----------------------------------
Accrued postretirement 
  benefit cost             $       0     $     0         $ (28.5)
-----------------------------------------------------------------
* Being amortized over a period of 20 years.

     To determine the accumulated postretirement benefit
obligation in 1995, 1994 and 1993, discount rates of 7 percent, 8
percent and 7.5 percent, respectively, were assumed. The assumed
long-term rate of return on plan assets was 8.5 percent for these
years. The health cost trend rate assumed for year 1995 was 10
percent, for the year 1996, 9 percent, and then declining
one-half percent per year to 5 percent for year 2004 and
thereafter. If the assumed health care cost trend rate were to be
increased by one percentage point each year, the accumulated
postretirement benefit obligation would increase by approximately
$130.9 million and the service cost and interest component of the
net periodic postretirement benefit cost would increase by $9.8
million.

      Postretirement plan assets consist of corporate common
stock and bonds, group annuity contracts, debt of the United
States government and its agencies and short-term securities.

<PAGE>
<PAGE>                       - 94 -

---------------------------------------------------------------- 
Note F  Contingencies
---------------------------------------------------------------- 

Indian Point.  Nuclear generating units similar in design to the
Company's Indian Point 2 unit have experienced problems of
varying severity in their steam generators, which in a number of
instances have required steam generator replacement. Inspections
of the Indian Point 2 steam generators since 1976 have revealed
various problems, some of which appear to have been arrested, but
the remaining service life of the steam generators is uncertain
and may be shorter than the unit's life. The projected service
life of the steam generators is reassessed periodically in the
light of the inspections made during scheduled outages of the
unit. Based on the latest available data, the Company estimates
that steam generator replacement will not be required before
1999, and possibly not until some years later. To avoid
procurement delays in the event replacement is necessary, the
Company purchased replacement steam generators, which are stored
at the site. If replacement of the steam generators is required,
such replacement is presently estimated (in 1995 dollars) to
require additional expenditures of approximately $107 million
(exclusive of replacement power costs) and an outage of
approximately six months. However, securing necessary permits and
approvals or other factors could require a substantially longer
outage if steam generator replacement is required on short
notice.

Nuclear Insurance.  The insurance policies covering the Company's
nuclear facilities for property damage, excess property damage,
and outage costs permit assessments under certain conditions to
cover insurers' losses. As of December 31, 1995 the highest
amount which could be assessed for losses during the current
policy year under all of the policies was $31.5 million. While
assessments may also be made for losses in certain prior years,
the Company is not aware of any losses in such years which it
believes are likely to result in an assessment.

     Under certain circumstances, in the event of nuclear
incidents at facilities covered by the federal government's
third-party liability indemnification program, the Company could
be assessed up to $79.3 million per incident of which not more
than $10 million may be assessed in any one year. The
per-incident limit is to be adjusted for inflation not later than
1998 and not less than once every five years thereafter.

     The Company participates in an insurance program covering
liabilities for injuries to certain workers in the nuclear power
industry. In the event of such injuries, the Company is subject
to assessment up to an estimated maximum of approximately $3.1
million.
<PAGE>
<PAGE>                       - 95 -

Environmental Matters.  The normal course of the Company's
operations necessarily involves activities and substances that
expose the Company to potential liabilities under federal, state
and local laws protecting the environment. Such liabilities can
be material and in some instances may be imposed without regard
to fault, or may be imposed for past acts, even though such past
acts may have been lawful at the time they occurred. Sources of
such potential liabilities include (but are not limited to) the
Federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 (Superfund), a 1994 settlement with the New
York State Department of Environmental Conservation (DEC),
asbestos, and electric and magnetic fields (EMF).

Superfund.  By its terms, Superfund imposes joint and several
strict liability, regardless of fault, upon generators of
hazardous substances for resulting removal and remedial costs and
environmental damages. The Company has received process or notice
concerning possible claims under Superfund or similar state
statutes relating to a number of sites at which it is alleged
that hazardous substances generated by the Company (and, in most
instances, a large number of other potentially responsible
parties) were deposited.  Estimates of the investigative,
removal, remedial and environmental damage costs (if any) the
Company will be obligated to pay with respect to each of these
sites range from extremely preliminary to highly refined. Based
on these estimates, the Company had accrued a liability at
December 31, 1995 of approximately $14.7 million. However, it is
possible that material additional costs in amounts not presently
determinable may be incurred with respect to these and other
sites.

DEC Settlement.  In November 1994 the Company agreed to a consent
order settling a civil administrative proceeding instituted by
the DEC in 1992, alleging environmental violations by the
Company. Pursuant to the consent order, the Company has conducted
an environmental management systems evaluation and is conducting
an environmental compliance audit. The Company also must
implement "best management practices"  plans for certain
facilities and undertake a remediation program at certain sites.
At December 31, 1995 the Company had an accrued liability of
$19.3 million for these sites. Expenditures for
environment-related projects in the five years 1996-2000,
including expenditures to comply with the consent order, are
currently estimated at $155 million. There will be additional
costs, including costs arising out of the compliance audit, the
materiality of which is not presently determinable.

<PAGE>
<PAGE>                       - 96 -

Asbestos Claims.  Suits have been brought in New York State and
federal courts against the Company and many other defendants,
wherein several thousand plaintiffs sought large amounts of
compensatory and punitive damages for deaths and injuries
allegedly caused by exposure to asbestos at various premises of
the Company. Many of these suits have been disposed of without
any payment by the Company, or for immaterial amounts. The
amounts specified in all the remaining suits total billions of
dollars but the Company believes that these amounts are greatly
exaggerated, as were the claims already disposed of. Based on the
information and relevant circumstances known to the Company at
this time, it is the opinion of the Company that these suits will
not have a material adverse effect on the Company's financial
position.

EMF.  Electric and magnetic fields are found wherever electricity
is used. Several scientific studies have raised concerns that EMF
surrounding electric equipment and wires, including power lines,
may present health risks. The Company is the defendant in several
suits claiming property damage or personal injury allegedly
resulting from EMF. In the event that a causal relationship
between EMF and adverse health effects is established, or
independently of any such causal determination, in the event of
adverse developments in related legal or public policy doctrines,
there could be a material adverse effect on the electric utility
industry, including the Company.

-----------------------------------------------------------------
Note G  Independent Power Producers (IPPs)
-----------------------------------------------------------------

The Company has contracts with IPPs for 1,798 MW of electric
generating capacity already in commercial operation, and
commitments for 186 MW of capacity expected to commence operation
in 1996 and about 70 MW of capacity expected to commence
operation after 1996. Under the three-year electric rate
agreement effective April 1, 1995, payments by the Company under
the contracts are reflected in rates. Assuming performance by the
IPPs, the Company is obligated over the terms of these contracts
(which extend for various periods, up to 2034) to make capacity
and other fixed (non-energy) payments. In addition, for energy
delivered under certain of these contracts, the Company is
obligated to pay variable prices that will exceed market prices
for energy.

     For the 1,798 MW of capacity in commercial operation,
capacity and other fixed (non-energy) payments are estimated for
the years 1996-2000 to be $282 million, $287 million, $293
million, $309 million and $432 million. Such payments gradually
increase to approximately $500 million in 2013, and thereafter
decline significantly.
<PAGE>
<PAGE>                       - 97 -

     Energy payments under the contracts for the years 1996-1999
(assuming performance by the IPPs) will exceed market prices by
an average estimated $200 million each year. Beginning in the
year 2000, the prices that the Company will be obligated to pay
for energy will approximate market levels.

-----------------------------------------------------------------
Note H  Federal Income Tax
-----------------------------------------------------------------
In the case of regulated utilities, SFAS 109 requires recognition
in the balance sheet of the revenue requirements to meet the
costs of future federal income taxes for temporary differences
for which deferred taxes had not previously been provided. The
net revenue requirements related to future federal income taxes
at December 31, 1995 and 1994 are shown on the following table.

-----------------------------------------------------------------
(Millions of Dollars)                     1995        1994
-----------------------------------------------------------------
Future federal income tax liability
  Temporary differences between the book 
  and tax bases of assets and liabilities:
   Property related                        $5,513.3     $5,389.1
   Reserve for injuries and damages           (49.2)       (43.9)
   Other                                       54.5         24.4
                                           ----------------------
   Total                                    5,518.6      5,369.6
                                           ----------------------
Future federal income tax computed
   at statutory rate - 35%                  1,931.5      1,879.4
Less: Accumulated deferred federal income
   taxes previously provided                1,254.0      1,160.5
                                            --------------------
Net future federal income tax expense for
 which deferred taxes have not been provided  677.5        718.9
                                             -------------------
Net revenue requirements for above 
(Regulatory asset--future federal 
   income taxes)*                            1,042.3     1,106.0
Add: Accumulated deferred federal
  income taxes previously provided           1,254.0     1,160.5
                                             -------------------
Total accumulated deferred 
   federal income tax                       $2,296.3    $2,266.5
-----------------------------------------------------------------
* Net revenue requirements will be offset by the amortization to
federal income tax expense of accumulated deferred investment tax
credits. Including the full effect therefrom, the net revenue
requirements related to future federal income taxes at December
31, 1995 and 1994 are $860.8 million and $914.5 million,
respectively.
<PAGE>
<PAGE>                                                              - 98 -
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------ 
Note H  Federal Income Tax, continued
------------------------------------------------------------------------------------------------------------------ 
Year Ended December 31 (Thousands of Dollars)                   1995                    1994            1993
<S>                                                         <C>                   <C>              <C>
------------------------------------------------------------------------------------------------------------------ 
Charged to:    Operations                                   $   396,560           $   438,160      $   366,020
               Other income                                       1,060                   430           (1,010)
------------------------------------------------------------------------------------------------------------------ 
Total federal income tax                                        397,620               438,590          365,010
------------------------------------------------------------------------------------------------------------------ 
Reconciliation of reported net income with taxable income
Federal income tax--current                                     328,600               374,500          270,800
Federal income tax--deferred                                     78,330                73,710          106,470
Investment tax credits deferred                                  (9,310)               (9,620)         (12,260)
------------------------------------------------------------------------------------------------------------------ 
Total federal income tax                                         397,620              438,590          365,010
Net income                                                       723,850              734,270          658,522
------------------------------------------------------------------------------------------------------------------ 
Income before federal income tax                               1,121,470            1,172,860        1,023,532
------------------------------------------------------------------------------------------------------------------ 
Effective federal income tax rate                                   35.5%                37.4%            35.7%
------------------------------------------------------------------------------------------------------------------ 
Adjustments decreasing (increasing) taxable income
Tax depreciation in excess of book depreciation:
       Amounts subject to normalization                          202,230              218,181          226,442
       Other                                                     (85,538)             (94,813)         (90,428)
Deferred recoverable fuel costs                                   61,937              (20,132)          (3,873)
Regulatory accounts receivable                                   (32,827)             (70,771)         (70,814)
Enlightened Energy program costs                                 (25,880)              29,677           59,297
Advance refunding of long-term debt                               (4,268)              (6,814)          86,346
Other--net                                                        34,240               44,263           34,155
------------------------------------------------------------------------------------------------------------------ 
Total                                                            149,894               99,591          241,125
------------------------------------------------------------------------------------------------------------------ 
Taxable income                                                   971,576            1,073,269          782,407
------------------------------------------------------------------------------------------------------------------ 
Federal income tax--current
Amount computed at statutory rate--35%*                          340,052              375,644          273,842
Tax credits                                                      (11,452)              (1,144)          (3,042)
------------------------------------------------------------------------------------------------------------------ 
Total                                                            328,600              374,500          270,800
------------------------------------------------------------------------------------------------------------------ 
Charged to:      Operations                                      328,200              374,160          271,140
                 Other income                                        400                  340             (340)
------------------------------------------------------------------------------------------------------------------ 
Total                                                            328,600              374,500          270,800
------------------------------------------------------------------------------------------------------------------ 
Federal income tax--deferred
Provisions for deferred federal income taxes consist of the 
  following tax effects of timing differences between tax 
  and book income:
Tax depreciation in excess of book depreciation                   66,133               72,597           76,193
Deferred recoverable fuel costs                                   21,678               (7,046)          (1,356)
Regulatory accounts receivable                                   (11,489)             (24,770)         (24,785)
Enlightened Energy program costs                                  (9,058)              10,387           20,754
Advance refunding of long-term debt                               (1,494)              (2,385)          30,221
Other--net                                                        12,560               24,927            5,443
------------------------------------------------------------------------------------------------------------------ 
Total                                                             78,330               73,710          106,470
------------------------------------------------------------------------------------------------------------------ 
Charged to:   Operations                                          77,670               73,620          107,140
              Other income                                           660                   90             (670)
------------------------------------------------------------------------------------------------------------------ 
Total                                                       $     78,330          $    73,710      $   106,470
------------------------------------------------------------------------------------------------------------------ 
* Under rate agreements, the effect of the increase in the statutory rate from 34% to 35% effective January 1, 1993
  was deferred until such effect could next be reflected in rates. The deferrals applicable to gas and steam operations
  were amortized over a twelve-month period which began October 1, 1993 when new rates became effective. For electric
  operations, deferrals for the year 1993 and the first three months of 1994 were amortized over a twelve-month period
  which began April 1, 1994 when new electric rates became effective.
</TABLE>

<PAGE>
<PAGE>                                                                 - 99 -
--------------------------------------------------------------------------------
Note I Financial Information by Business Segments(a) (Thousands of Dollars)
--------------------------------------------------------------------------------
<TABLE> 
<CAPTION>                                              Electric                                         Steam
                                        ----------------------------------------          -----------------------------------------
                                           1995          1994            1993                 1995          1994            1993 
--------------------------------------------------------------------------------          -----------------------------------------
<S>                                     <C>            <C>            <C>                 <C>            <C>            <C> 
Operating revenues*                     $5,401,524     $5,152,351     $5,145,010          $   335,694    $   343,916    $   326,888
--------------------------------------------------------------------------------          -----------------------------------------
Operating expenses                                                                                                                 
Fuel                                       354,086        410,173        446,578              150,018        157,591        158,635
Purchased power                          1,107,223        787,455        812,616                 --             --             --
Other operations and maintenance*        1,372,715      1,372,865      1,403,022               79,929         80,035         78,787
Depreciation and amortization              393,382        364,988        350,590               13,064         10,961          9,909
Taxes, other than federal income           951,095        955,850        994,174               45,788         46,178         46,090
Federal income tax                         339,863        379,584        322,076               12,598         11,577          4,966
--------------------------------------------------------------------------------          -----------------------------------------
Total operating expenses*                4,518,364      4,270,915      4,329,056              301,397        306,342        298,387
--------------------------------------------------------------------------------          -----------------------------------------
Operating income                           883,160        881,436        815,954               34,297         37,574         28,501
--------------------------------------------------------------------------------          -----------------------------------------
Construction expenditures                  538,454        587,189        626,494               27,559         44,957         36,612
--------------------------------------------------------------------------------          -----------------------------------------
Net utility plant**                      9,027,031      8,874,341      8,592,187              399,028        378,748        337,713
Fuel                                        40,444         50,821         53,681                   62             62             74
Other identifiable assets                1,724,005      1,899,182      1,970,998               51,969         48,141         50,555
--------------------------------------------------------------------------------          -----------------------------------------
*Intersegment rentals included in segments' income but eliminated for total Company
        Operating revenues                 $12,116       $11,879         $13,345              $ 1,561        $ 1,409        $ 1,548 
        Operating expenses                   2,513         2,331           2,726               13,102         12,733         14,139
-----------------------------------------------------------------------------------------------------------------------------------
<CAPTION>                                                  Gas                                         Total Company
                                        ----------------------------------------          -----------------------------------------
                                            1995           1994          1993                 1995           1994          1993
--------------------------------------------------------------------------------          -----------------------------------------
Operating revenues*                     $  815,307     $  891,897     $  810,377          $ 6,536,897    $ 6,373,086    $ 6,265,394
--------------------------------------------------------------------------------          -----------------------------------------
<S>                                     <C>            <C>            <C>                 <C>            <C>            <C> 
Operating expenses                                                                                                                 
Fuel                                          --             --             --                504,104        567,764        605,213
Purchased power                               --             --             --              1,107,223        787,455        812,616
Gas purchased for resale                   259,789        341,204        289,708              259,789        341,204        289,708
Other operations and maintenance*          214,818        214,451        212,832            1,651,834      1,652,273      1,677,760
Depreciation and amortization               49,330         46,407         43,231              455,776        422,356        403,730
Taxes, other than federal income           123,349        125,663        119,019            1,120,232      1,127,691      1,159,283
Federal income tax                          44,099         46,999         38,978              396,560        438,160        366,020
--------------------------------------------------------------------------------          -----------------------------------------
Total operating expenses*                  691,385        774,724        703,768            5,495,518      5,336,903      5,314,330
--------------------------------------------------------------------------------          -----------------------------------------
Operating income                           123,922        117,173        106,609            1,041,379      1,036,183        951,064
--------------------------------------------------------------------------------          -----------------------------------------
Construction expenditures                  126,790        125,384        125,962              692,803        757,530        789,068
--------------------------------------------------------------------------------          -----------------------------------------
Net utility plant**                      1,388,344      1,308,119      1,226,256           10,814,403     10,561,208     10,156,156
Fuel and gas in storage                     26,452         50,698         49,091               66,958        101,581        102,846
Other identifiable assets                  177,374        151,628        172,790            1,953,348      2,098,951      2,194,343
Other corporate assets                                                                      1,115,181        966,624        804,020
--------------------------------------------------------------------------------          -----------------------------------------
Total assets                                                                              $13,949,890    $13,728,364    $13,257,365
--------------------------------------------------------------------------------          -----------------------------------------
*Intersegment rentals included in segments' income but eliminated for total Company 
        Operating revenues                 $ 1,951        $ 1,790        $ 1,988              $15,628        $15,078        $16,881
        Operating expenses                      13             14             16               15,628         15,078         16,881 
</TABLE> 
** General Utility Plant was allocated to Electric and Gas on the basis of the
   departmental use of such plant. Pursuant to PSC requirements the Steam
   department is charged an interdepartmental rent for General Plant used in
   Steam operations which is credited to the Electric and Gas departments.
--------------------------------------------------------------------------------
(a) The Company supplies electric service in all of New York City (except part
      of Queens) and most of Westchester County. It also supplies gas in
      Manhattan, The Bronx and parts of Queens and Westchester, and steam in
      part of Manhattan.
<PAGE>
<PAGE>                         - 100 -
<TABLE>
                                                                              SCHEDULE VIII




                  CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.

                        VALUATION AND QUALIFYING ACCOUNTS
                          YEAR ENDED DECEMBER 31, 1995
                             (Thousands of Dollars)




<S>                           <C>           <C>            <C>         <C>          <C>
    COLUMN A                    COLUMN B            COLUMN C             COLUMN D     COLUMN E
                                                    Additions        
                                                (1)          (2)
                               Balance at    Charged to    Charged to                 Balance
                               Beginning     Costs and       Other                    At End
Description                    of Period      Expenses      Accounts    Deductions   of Period

Valuation Accounts              
  deducted in the balance
  sheet from the assets to
  which they apply:

Accumulated Provision
  for uncollectible
  accounts receivable:

  Electric, Gas and
    Steam Customers........     $ 21,600      $ 32,589         -         $ 32,589*     $ 21,600

  Other....................         -             -            -             -             -   






*Accounts written off less cash collections, miscellaneous adjustments and amounts reinstated
 as receivables previously written off.

</TABLE>
<PAGE>
<PAGE>                         - 101 -
<TABLE>
                                                                              SCHEDULE VIII




                  CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.

                        VALUATION AND QUALIFYING ACCOUNTS
                          YEAR ENDED DECEMBER 31, 1994
                             (Thousands of Dollars)




<S>                           <C>           <C>                         <C>          <C>
    COLUMN A                    COLUMN B            COLUMN C             COLUMN D     COLUMN E
                                                    Additions        
                                                (1)          (2)
                               Balance at    Charged to    Charged to                 Balance
                               Beginning     Costs and       Other                    At End
Description                    of Period      Expenses      Accounts    Deductions   of Period

Valuation Accounts              
  deducted in the balance
  sheet from the assets to
  which they apply:

Accumulated Provision
  for uncollectible
  accounts receivable:

  Electric, Gas and
    Steam Customers........     $ 21,600      $ 30,256         -         $ 30,256*     $ 21,600

  Other....................         -             -            -             -             -   






*Accounts written off less cash collections, miscellaneous adjustments and amounts reinstated
 as receivables previously written off.

</TABLE>
<PAGE>
<PAGE>                         - 102 -
<TABLE>
                                                                              SCHEDULE VIII



                  CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.

                        VALUATION AND QUALIFYING ACCOUNTS
                          YEAR ENDED DECEMBER 31, 1993
                             (Thousands of Dollars)




<S>                            <C>           <C>           <C>          <C>          <C>
    COLUMN A                    COLUMN B              COLUMN C           COLUMN D     COLUMN E
                                                      Additions      
                                                (1)          (2)
                               Balance at    Charged to    Charged to                 Balance
                               Beginning     Costs and       Other                     At End
Description                    of Period      Expenses      Accounts    Deductions   of Period

Valuation Accounts              
  deducted in the balance
  sheet from the assets to
  which they apply:

Accumulated Provision
  for uncollectible
  accounts receivable:

  Electric, Gas and
    Steam Customers........     $ 19,600      $ 28,006         -         $ 26,006*     $ 21,600

  Other....................         -             -            -             -             -   






*Accounts written off less cash collections, miscellaneous adjustments and amounts reinstated
 as receivables previously written off.

</TABLE>
<PAGE>
<PAGE>                         - 103 -

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

ITEM 11.  EXECUTIVE COMPENSATION

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
          MANAGEMENT

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Information required by Part III is incorporated by
reference from the Company's definitive proxy statement for its
Annual Meeting of Stockholders to be held on May 20, 1996.  The
proxy statement is to be filed pursuant to Regulation 14A not
later than 120 days after December 31, 1995, the close of the
fiscal year covered by this report.

     In accordance with General Instruction G(3) to Form 10-K
other information regarding the Company's Executive Officers may
be found in Part I of this report under the caption "Executive
Officers of the Registrant."

<PAGE>
<PAGE>                         - 104 -

                             PART IV

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

(a)       Documents filed as part of this report:

     1.   List of Financial Statements

             Consolidated Balance Sheet at December 31, 1995 and
             1994

             Consolidated Income Statement for the years ended
             December 31, 1995, 1994 and 1993

             Consolidated Statement of Cash Flows for the years
             ended December 31, 1995, 1994 and 1993

             Consolidated Statement of Capitalization at December
             31, 1995 and 1994

             Consolidated Statement of Retained Earnings for the
             years ended December 31, 1995, 1994 and 1993

             Notes to Consolidated Financial Statements

     2.   List of Financial Statement Schedules

             Valuation and Qualifying Accounts
             (Schedule VIII)



<PAGE>
<PAGE>                         - 105 -

     3.   List of Exhibits

    3.1.1 Restated Certificate of Incorporation filed with the
          Department of State of the State of New York on
          December 31, 1984.  (Designated in the Company's Annual
          Report on Form 10-K for the year ended December 31,
          1989 (File No. 1-1217) as Exhibit 3(a).)

    3.1.2 Certificate of Amendment of Restated Certificate of
          Incorporation filed with the Department of State of the
          State of New York on May 16, 1988.  (Designated in the
          Company's Annual Report on Form 10-K for the year ended
          December 31, 1989 (File No. 1-1217) as Exhibit 3(b).)

    3.1.3 Certificate of Amendment of Restated Certificate of
          Incorporation filed with the Department of State of the
          State of New York on June 2, 1989.  (Designated in the
          Company's Annual Report on Form 10-K for the year ended
          December 31, 1989 (File No. 1-1217) as Exhibit 3(c).)

    3.1.4 Certificate of Amendment of Restated Certificate of
          Incorporation filed with the Department of State of the
          State of New York on April 28, 1992.  (Designated in
          the Company's Current Report on Form 8-K, dated April
          24, 1992, as Exhibit 4(d).)

    3.1.5 Certificate of Amendment of Restated Certificate of
          Incorporation filed with the Department of State of the
          State of New York on August 21, 1992.  (Designated in
          the Company's Current Report on Form 8-K, dated August
          20, 1992, as Exhibit 4(e).)

    3.2.1 By-laws of the Company, effective as of July 26, 1994.  
          (Designated in the Company's Quarterly Report on Form
          10-Q for the quarter ended June 30, 1994 as Exhibit
          3.2.) 

   *3.2.2 Resolution adopted March 26, 1996 by the Board of
          Trustees of the Company amending the Company's
          By-Laws.

   *3.2.3 By-laws of the Company, effective as of May 20,
          1996.

      4.1 Indenture, dated as of April 1, 1946, between the
          Company and the National City Bank of New York (now
          Citibank, N.A.), as Trustee.  (Designated in
          Registration Statement No. 2-6932 as Exhibit 7-48.)
<PAGE>
<PAGE>                         - 106 -

      4.2 The following Supplemental Indentures between the
          Company and the National City Bank of New York (now
          Citibank, N.A.), as Trustee, which are designated as
          follows:

                           Securities Act
            Supplemental    Registration 
              Indenture      Statement      Exhibit

          1. Fifteenth        2-13939         2-4
          2. Twenty-ninth     2-24272         4-4
          3. Thirtieth        2-25736         4-4

      4.3 Instrument of Resignation, Appointment and Acceptance,
          dated as of October 31, 1979, among the Company,
          Citibank, N.A., and Chemical Bank, Supplemental to
          Mortgage Trust Indenture, dated as of April 1, 1946. 
          (Designated in the Company's Annual Report on Form 10-K
          for the year ended December 31, 1991 as Exhibit 4(c).)

      4.4 Participation Agreement, dated as of August 15, 1985,
          between New York State Energy Research and Development
          Authority ("NYSERDA") and the Company.  (Designated in
          the Company's Quarterly Report on Form 10-Q for the
          quarter ended June 30, 1990 as Exhibit 4(a)(1).)

      4.5 The following Supplemental Participation Agreements
          supplementing the Participation Agreement, dated as of
          August 15, 1985, between NYSERDA and the Company, which
          are designated as follows:

                  Supplemental          Securities Exchange Act
             Participation Agreement        File No. 1-1217
                Number      Date       Form    Date      Exhibit

             1. First     11/15/86     10-Q   6/30/90    4(a)(2)
             2. Second     4/15/87     10-Q   6/30/90    4(a)(3)
             3. Third      9/15/87     10-Q   6/30/90    4(a)(4)
             4. Fourth      1/1/89     10-Q   6/30/90    4(a)(5)
             5. Fifth       7/1/89     10-Q   6/30/90    4(a)(6)
             6. Sixth      11/1/89     10-Q   6/30/90    4(a)(7)
             7. Seventh     7/1/90     10-Q   6/30/90    4(a)(8)
             8. Eighth      1/1/91     10-K  12/31/90    4(e)(8)
             9. Ninth      1/15/92     10-K  12/31/91    4(e)(9)

       4.6 Participation Agreement, dated as of December 1, 1992,
           between NYSERDA and the Company.  (Designated in the
           Company's Annual Report on Form 10-K for the year
           ended December 31, 1992 as Exhibit 4(f).)
<PAGE>
<PAGE>                         - 107 -
      4.7 The following Supplemental Participation Agreements
          supplementing the Participation Agreement, dated as of
          December 1, 1992, between NYSERDA and the Company, 
          which are designated as follows:
                  Supplemental          Securities Exchange Act
             Participation Agreement        File No. 1-1217
                Number       Date      Form     Date     Exhibit
             1. First      3/15/93     10-Q   6/30/93      4.1
             2. Second     10/1/93     10-Q   9/30/93      4.3
             3. Third      12/1/94     10-K  12/31/94      4.7.3
             4. Fourth      7/1/95     10-Q   6/30/95      4.2

       4.8 Indenture of Trust, dated as of August 15, 1985,
           between NYSERDA and Morgan Guaranty Trust Company of
           New York, as Trustee ("Morgan Guaranty"). (Designated
           in the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1990 as Exhibit 4(b)(1).)

       4.9 The following Supplemental Indentures of Trust
           supplementing the Indenture of Trust, dated as of
           August 15, 1985, between NYSERDA and Morgan Guaranty.

                    Supplemental          Securities Exchange Act
                Indenture of Trust            File No. 1-1217     
                  Number    Date         Form    Date    Exhibit
                1. First  11/15/86       10-Q   6/30/90  4(b)(2)
                2. Second  4/15/87       10-Q   6/30/90  4(b)(3)
                3. Third   9/15/87       10-Q   6/30/90  4(b)(4)
                4. Fourth   1/1/89       10-Q   6/30/90  4(b)(5)
                5. Fifth    7/1/89       10-Q   6/30/90  4(b)(6)
                6. Sixth   11/1/89       10-Q   6/30/90  4(b)(7)
                7. Seventh  7/1/90       10-Q   6/30/90  4(b)(8)
                8. Eighth   1/1/91       10-K  12/31/90  4(g)(8)
                9. Ninth   1/15/92       10-K  12/31/91  4(g)(9)

     4.10  Indenture of Trust, dated as of December 1, 1992,
           between NYSERDA and Morgan Guaranty Trust Company of
           New York, as Trustee ("Morgan Guaranty").  (Designated 
           in the Company's Annual Report on Form 10-K for the
           year ended December 31, 1992 as Exhibit 4(i).)

     4.11  The following Supplemental Indentures of Trust
           supplementing the Indenture of Trust, dated as of
           December 1, 1992, between NYSERDA and Morgan Guaranty.
                    Supplemental         Securities Exchange Act
                 Indenture of Trust           File No. 1-1217     
                   Number   Date         Form    Date    Exhibit

                1. First   3/15/93       10-Q   6/30/93    4.2
                2. Second  10/1/93       10-Q   9/30/93    4.4
                3. Third   12/1/94       10-K  12/31/94    4.11.3
                4. Fourth   7/1/95       10-Q   6/30/95    4.3
<PAGE>
<PAGE>                         - 108 -

      4.12 Indenture, dated as of December 1, 1990, between the
           Company and The Chase Manhattan Bank (National
           Association), as Trustee (the "Debenture Indenture").
           (Designated in the Company's Annual Report on Form
           10-K for the year ended December 31, 1990 as Exhibit
           4(h).)

     *4.13 First Supplemental Indenture (to the Debenture
           Indenture), dated as of March 6, 1996, between the
           Company and The Chase Manhattan Bank (National
           Association), as Trustee.

      4.14 The following Forms of the Company's Debentures:

                                      Securities Exchange Act
                                           File No. 1-1217
                 Debenture            Form    Date   Exhibit

           9.70%,  Series 1990 A      8-K   11/29/90    4
          9 3/8%,  Series 1991 A      8-K    6/20/91    4
          7 3/8%,  Series 1992 A      8-K     2/5/92    4(a)
          7 5/8%,  Series 1992 B      8-K     2/5/92    4(b)
           7.60%,  Series 1992 C      8-K    2/25/92    4
          6 1/2%,  Series 1992 D      8-K    8/26/92    4(a)
          7 3/8%,  Series 1992 E      8-K    8/26/92    4(b)
           8.05%,  Series 1992 F      8-K   12/15/92    4
          6 1/4%,  Series 1993 A      8-K    1/13/93    4
          6 1/2%,  Series 1993 B      8-K     2/4/93    4(a)
          6 5/8%,  Series 1993 C      8-K     2/4/93    4(b)
          6 3/8%,  Series 1993 D      8-K     4/7/93    4
           5.30%,  Series 1993 E      8-K    5/19/93    4(a)
           5.70%,  Series 1993 F      8-K    5/19/93    4(b)
          7 1/2%,  Series 1993 G      8-K     6/7/93    4
          7 1/8%   Series 1994 A      8-K     2/8/94    4
     Floating Rate Series 1994 B      8-K     6/29/94   4
          6 5/8%   Series 1995 A      8-K     6/21/95   4

      4.15 Form of the Company's 7 3/4% Quarterly Income Capital
           Securities (Series A Subordinated Deferrable Interest
           Debentures).  (Designated in the Company's Current
           Report on Form 8-K, dated February 29, 1996, as
           Exhibit 4.)

      10.1 Agreement dated as of October 31, 1968 among Central
           Hudson Gas & Electric Corporation, the Company and
           Niagara Mohawk Power Corporation.  (Designated in
           Registration Statement No. 2-31884 as Exhibit 7.)

<PAGE>
<PAGE>                         - 109 -

      10.2 Amendment dated November 23, 1976 to Agreement dated
           as of October 31, 1968 among Central Hudson Gas &
           Electric Corporation, the Company and Niagara Mohawk
           Power Corporation and Additional Agreement dated as of
           November 23, 1976 between Central Hudson and the
           Company.  (Designated in the Company's Annual Report
           on Form 10-K for the year ended December 31, 1991 as
           Exhibit 10(b).)

      10.3 General Agreement between Orange and Rockland
           Utilities, Inc. and the Company dated October 10,
           1969.  (Designated in Registration Statement No.
           2-35734 as Exhibit 7-1.)

      10.4 Letters, dated November 18, 1970 and November 23,
           1970, between Orange and Rockland Utilities, Inc. and
           the Company pursuant to Article 14(a) of the aforesaid
           General Agreement.  (Designated in Registration
           Statement No. 2-38807 as Exhibit 5-3.)

      10.5 The Con Edison Thrift Savings Plan for Management
           Employees and Tax Reduction Act Stock Ownership Plan,
           as amended and restated.  (Designated in the Company's
           Quarterly Report on Form 10-Q for the quarter ended
           September 30, 1995 as Exhibit 10.2.)

      10.6 Deferred Compensation Plan for the Benefit of Trustees
           of the Company, dated February 27, 1979, and
           amendments thereto, dated September 19, 1979
           (effective February 27, 1979), February 26, 1980, and
           November 24, 1992 (effective January 1, 1993).
           (Designated in Company's Annual Report on Form 10-K
           for the year ended December 31, 1992 as Exhibit
           10(i).)

      10.7 Employment contract, dated August 24, 1982, between
           the Company and Arthur Hauspurg, as amended. 
           (Designated in the Company's Annual Report on Form
           10-K for the year ended December 31, 1991 as Exhibit
           10(i).)

      10.8 Agreement, dated January 24, 1991, between the Company
           and Arthur Hauspurg. (Designated in the Company's
           Annual Report on Form 10-K for the year ended December
           31, 1990 as Exhibit 10(l).)

      10.9 Employment Contract, dated May 22, 1990, between the
           Company and Eugene R. McGrath.  (Designated in the
           Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1990 as Exhibit 10.)
<PAGE>
<PAGE>                         - 110 -

     10.10 Amendment, dated August 27, 1991, to Employment
           Contract dated May 22, 1990, between the Company and
           Eugene R. McGrath.  (Designated in the Company's
           Quarterly Report on Form 10-Q for the quarter ended
           September 30, 1991 as Exhibit 19.)

     10.11 Amendment, dated August 25, 1992, to Employment
           Contract, dated May 22, 1990, between the Company and
           Eugene R. McGrath.  (Designated in the Company's
           Quarterly Report on Form 10-Q for the quarter ended
           September 30, 1992 as Exhibit 19.)

     10.12 Amendment, dated February 18, 1993, to Employment
           Contract dated May 22, 1990, between the Company and
           Eugene R. McGrath. (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1992 as Exhibit 10(o).)

     10.13 Amendment, dated August 24, 1993, to Employment
           Contract dated May 22, 1990, between the Company and
           Eugene R. McGrath.  (Designated in the Company's
           Quarterly Report on Form 10-Q for the quarterly
           period ended September 30, 1993 as Exhibit 10.1.)

     10.14 Amendment, dated August 24, 1994, to Employment
           Contract, dated May 22, 1990, between the Company and
           Eugene R. McGrath.  (Designated in the Company's
           Quarterly Report on Form 10-Q for the quarterly
           period ended September 30, 1994 as Exhibit 10.1.)

     10.15 Amendment, dated August 22, 1995, to Employment
           Contract, dated May 22, 1990, between the Company
           and Eugene R. McGrath.  (Designated as in the
           Company's Quarterly Report on Form 10-Q for the
           quarterly period ended September 30, 1995 as
           Exhibit 10.3.)

     10.16 Agreement, effective March 1, 1989, between Raymond J.
           McCann and the Company as to salary and deferred
           compensation.  (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1992 as Exhibit 10(p).)

     10.17 Amendment, dated February 27, 1990, to Agreement,
           effective March 1, 1989, between Raymond J. McCann and
           the Company.  (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1989 (File No. 1-1217) as Exhibit 10(w).)
<PAGE>
<PAGE>                         - 111 -

     10.18 Amendment, dated November 27, 1990, to Agreement, 
           effective March 1, 1989, between Raymond J. McCann and
           the Company.  (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1990 as Exhibit 10(r).)

     10.19 Amendment, dated March 11, 1992, to Agreement,
           effective March 1, 1989, between Raymond J. McCann and
           the Company.  (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1991, as Exhibit 10(p).)

     10.20 Amendment, dated February 18, 1993, to Agreement,
           effective March 1, 1989, between Raymond J. McCann and
           the Company.  (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1992 as Exhibit 10(t).)

     10.21 Amendment, dated March 10, 1993, to Agreement,
           effective March 1, 1989, between Raymond J. McCann and
           the Company.  (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1992 as Exhibit 10(u).)

     10.22 Amendment, dated March 10, 1994, to Agreement,
           effective March 1, 1989, between Raymond J. McCann and
           the Company.  (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1993 as Exhibit 10.23.)

     10.23 Amendment, dated March 1, 1995, to Agreement,
           effective March 1, 1989, between Raymond J. McCann and
           the Company.  (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1994 as Exhibit 10.22.)

    *10.24 Amendment, dated March 28, 1996, to Agreement,
           effective March 1, 1989, between Raymond J. McCann
           and the Company.

     10.25 The Consolidated Edison Company of New York, Inc.
           Executive Incentive Plan adopted by the Company's
           Board of Trustees on March 23, 1982 as amended through
           March 30, 1989.  (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1991, as Exhibit 10(q).)
<PAGE>
<PAGE>                         - 112 -

     10.26 Amendment and Restatement, dated August 26, 1991 and
           effective as of April 30, 1991, of The Consolidated
           Edison Company of New York, Inc. Executive Incentive
           Plan.  (Designated in the Company's Annual Report on
           Form 10-K for the year ended December 31, 1991 as
           Exhibit 10(r).)

     10.27 Amendment and Restatement, dated January 29, 1992 and
           effective as of December 1, 1991, of The Consolidated
           Edison Company of New York, Inc. Executive Incentive
           Plan.  (Designated in the Company's Annual Report on
           Form 10-K for the year ended December 31, 1991 as
           Exhibit 10(s).)

     10.28 The Consolidated Edison Retirement Plan for Management
           Employees, as amended and restated.  (Designated in
           the Company's Quarterly Report on Form 10-Q for the
           quarterly period ended September 30, 1995 as Exhibit
           10.1.).

   * 10.29 Amendment No. 1, dated December 29, 1995, to the
           Consolidated Edison Retirement Plan for Management
           Employees.

     10.30 Con Edison Supplemental Retirement Income Plan,
           adopted July 22, 1987, effective January 1, 1987.
           (Designated in the Company's Annual Report on Form
           10-K for the year ended December 31, 1992 as Exhibit
           10(cc).)

     10.31 Copy of memorandum and resolutions adopted by the
           Company's Board of Trustees on August 23, 1983 
           authorizing additional compensation for certain
           officers of the Company and permitting the deferral by
           the officers of certain compensation. (Designated in
           the Company's Annual Report on Form 10-K for the year
           ended December 31, 1992 as Exhibit 10(dd).)

     10.32 Consolidated Edison Company of New York, Inc.
           Retirement Plan for Trustees, effective as of July 1,
           1988. (Designated in the Company's Annual Report on
           Form 10-K for the year ended December 31, 1992 as
           Exhibit 10(ee).)

     10.33 Amendment No. 1, dated September 28, 1990, to the
           Consolidated Edison Company of New York, Inc.
           Retirement Plan for Trustees.  (Designated in the
           Company's Quarterly Report on Form 10-Q for the
           quarter ended September 30, 1990 as Exhibit 19(c).)

     10.34 Planning and Supply Agreement, dated March 10, 1989,
           between the Company and the Power Authority of the
           State of New York. (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1992 as Exhibit 10(gg).)
<PAGE>
<PAGE>                         - 113 -

     10.35 Delivery Service Agreement, dated March 10, 1989,
           between the Company and the Power Authority of the
           State of New York. (Designated in the Company's Annual
           Report on Form 10-K for the year ended December 31,
           1992 as Exhibit 10(hh).)

     10.36 Supplemental Medical Plan for the Benefit of the
           Company's officers.  (Designated in the Company's
           Annual Report on Form 10-K for the year ended December
           31, 1991, as Exhibit 10(aa).)

     10.37 The Con Edison Discount Stock Purchase Plan.
           (Designated in the Company's Annual Report on Form
           10-K for the year ended December 31, 1991, as Exhibit
           10(bb).)

    *10.38 Amendment, dated December 29, 1995, to the Con Edison
           Discount Stock Purchase Plan.

     10.39 Employment Agreement, dated June 25, 1991, between the
           Company and J. Michael Evans.  (Designated in the
           Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1991 as Exhibit 19.)

     10.40 Amendment, dated March 29, 1993, to Employment
           Agreement, dated June 25, 1991, between the Company
           and J. Michael Evans.  (Designated in the Company's
           Quarterly Report on Form 10-Q for the quarter ended
           March 31, 1993 as Exhibit 10.)

     10.41 Amendment, dated November 8, 1993, to Employment
           Agreement, dated June 25, 1991, between the Company
           and J. Michael Evans.  (Designated in the Company's
           Quarterly Report on Form 10-Q for the quarter ended
           September 30, 1993 as Exhibit 10.2.)

     10.42 The Consolidated Edison Retiree Health Program for
           Management Employees, effective as of January 1, 1993.
           (Designated in the Company's Annual Report on Form
           10-K for the year ended December 31, 1992 as Exhibit
           10(ll).)

     10.43 Amendment No. 1, dated October 31, 1994, to the
           Consolidated Edison Retiree Health Program for
           Management Employees.  (Designated in the Company's
           Quarterly Report on Form 10-Q for the quarterly period
           ended September 30, 1994 as Exhibit 10.3.)

    *10.44 Amendment No. 2, dated December 28, 1994, to the
           Consolidated Edison Retiree Health Program for
           Management Employees.

    *10.45 Amendment No. 3, dated December 29, 1995, to the
           Consolidated Edison Retiree Health Program for
           Management Employees.


<PAGE>
<PAGE>                         - 114 -

    *10.46 Employment Agreement, dated November 28, 1995, between
           the Company and Peter J. O'Shea, Jr.

    *10.47 Consolidated Edison Company of New York, Inc. 1996
           Stock Option Plan.

     12    Statement of computation of ratio of earnings to fixed
           charges for the years ended December 31, 1995, 1994,
           1993, 1992 and 1991.  (Designated in the Company's 
           Current Report on Form 8-K, dated February 29, 1996,
           as Exhibit 12.)

    *23   Consent of Price Waterhouse LLP.

    *24   Powers of Attorney of each of the persons signing this
          report by attorney-in-fact.

     27   Financial Data Schedule.  (Designated in the Company's
          Current Report on Form 8-K, dated February 29, 1996,
          as Exhibit 27.1)  (To the extent provided in
          Rule 402 of Regulation S-T, this exhibit shall not be
          deemed "filed", or otherwise subject to liabilities, or
          be deemed part of a registration statement.)

     Exhibits listed above which have been filed with the
Securities and Exchange Commission pursuant to the Securities Act
of 1933 and the Securities Exchange Act of 1934, and which were
designated as noted above, are hereby incorporated by reference
and made a part of this report with the same effect as if filed
with the report.


     ____________________
     * Filed herewith
<PAGE>
<PAGE>                         - 115 -

(b)  Reports on Form 8-K:

     During the quarter ended December 31, 1995, the Company
filed no Current Reports on Form 8-K.

     The Company filed a Current Report on Form 8-K, dated
February 29, 1996, reporting (under Item 5) the sale of $275
million aggregate principal amount of its 7 3/4% Quarterly Income
Capital Securities (Series A Subordinated Deferrable Interest
Debentures), and the expect use of the net proceeds of the sale
thereof to refund certain preferred stock of the Company.  The
Form 8-K included as Exhibits 99.2 and 99.4, respectively, the
financial statements included in Item 8 herein and the
Management's Discussion and Analysis of Financial Condition and
Results of Operations included in Item 7 herein.
<PAGE>
<PAGE>                         - 116 -

                             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.

                   CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.

     Date:  March 28, 1996        By     Raymond J. McCann
                                         Raymond J. McCann
                                     Executive Vice President & 
                                       Chief Financial Officer

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

     Date          Signature                  Title

March 28, 1996     Eugene R. McGrath*  Chairman of the Board,
                                     President, Chief Executive
                                         Officer and Trustee
                                   (Principal Executive Officer)

March 28, 1996     Raymond J. McCann*  Executive Vice President
                                      & Chief Financial Officer
                                           and Trustee
                                   (Principal Financial Officer)

March 28, 1996     Joan S. Freilich* Vice President, Controller
                                    and Chief Accounting Officer
                                   (Principal Accounting Officer)
                   E. Virgil Conway*         Trustee
                   Gordon J. Davis*          Trustee
                   Ruth M. Davis*            Trustee
                   Ellen V. Futter*          Trustee
                   Arthur Hauspurg*          Trustee
                   Sally Hernandez-Pinero*   Trustee
                   Peter W. Likins*          Trustee
                   Frederick P. Rose*        Trustee
                   Donald K. Ross*           Trustee
                   Robert G. Schwartz*       Trustee
                   Richard A. Voell*         Trustee
                   Myles V. Whalen, Jr.*     Trustee

March 28, 1996  *By    Raymond J. McCann  Attorney-in-Fact
                       Raymond J. McCann