FORM 10-K

                      Securities and Exchange Commission
                            Washington, D.C. 20549



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

                 For the fiscal year ended DECEMBER 31, 1996

                                      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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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.,
7 3/4% Quarterly Income Capital Securities (Series A     New York Stock Exchange
   Subordinated Deferrable Interest Debentures)
$5 Cumulative Preferred Stock, without par value         New York Stock Exchange
Cumulative Preferred Stock, 4.65% Series C               New York Stock Exchange
     ($100 par value)
Cumulative Preference Stock, 6% Convertible Series B
    ($100 par value)                                     New York Stock Exchange
Common Stock ($2.50 par value)                           New York, Chicago and
                                                         Pacific Stock Exchanges
Kings County Electric Light and Power Company,
Purchase Money, 6%, 99 Years Gold Bonds, due             New York Stock Exchange
   due October 1, 1997 (non-callable)


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

Title of each class

Consolidated Edison Company of New York, Inc., Cumulative Preferred Stock,
   4.65% Series D ($100 par value)


      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. [ X ]

      The aggregate market value of the voting stock held by  non-affiliates  of
the registrant,  as of January 31, 1997, was $7,414,319,109.  Excluded from this
figure is  $1,862,666  representing  the market value of 60,086 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 28, 1997, the registrant had outstanding 235,004,373 shares
of Common Stock.

                     Documents Incorporated By Reference

      Portions of the  registrant's  Proxy Statement for its 1997 Annual Meeting
of Stockholders,  to be filed with the Commission pursuant to Regulation 14A not
later than 120 days  after  December  31,  1996,  the close of the  registrant's
fiscal year, are incorporated in Part III of this report.


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                              TABLE OF CONTENTS

                                                                       Page
PART I

ITEM 1.  Business                                                           4
ITEM 2.  Properties                                                        20
ITEM 3.  Legal Proceedings                                                 23
ITEM 4.  Submission of Matters to a Vote of Security Holders              None

Executive Officers of the Registrant                                       31


PART II

ITEM 5.  Market for the Registrant's Common Equity
               and Related Stockholder Matters                             36
ITEM 6.  Selected Financial Data                                           36
ITEM 7.  Management's Discussion and Analysis of
               Financial Condition and Results of Operations               37
ITEM 8.  Financial Statements and Supplementary Data                       47
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   69


SIGNATURES                                                                 79

-------------------
*Incorporated by reference from the Company's definitive proxy statement for its
Annual Meeting of Stockholders to be held on May 19, 1997.



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PART I


ITEM 1.     BUSINESS

Contents of Item 1                                                       Page

THE COMPANY                                                                4
INDUSTRY SEGMENTS                                                          5
ELECTRIC OPERATIONS                                                        5
GAS OPERATIONS                                                             8
STEAM OPERATIONS                                                          10
COMPETITIVE BUSINESSES AND COMPETITION                                    11
CAPITAL REQUIREMENTS AND FINANCING                                        11
FUEL SUPPLY                                                               12
REGULATION AND RATES                                                      14
ENVIRONMENTAL MATTERS AND RELATED LEGAL PROCEEDINGS                       15
GENERAL                                                                   17
EMPLOYEES                                                                 17
RESEARCH AND DEVELOPMENT                                                  17
OPERATING STATISTICS                                                      18


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.  State and municipal  customers within the Company's
service  territory  receive  electric  service from the New York Power Authority
(NYPA) through the Company's facilities.

      The New York State Public Service  Commission  (PSC),  by order issued and
effective May 20, 1996 in its "Competitive Opportunities" proceeding, endorsed a
fundamental  restructuring  of the electric  utility industry in New York State,
based on  competition  in the  generation  and  energy  services  sectors of the
industry.  On March  13,  1997,  Con  Edison  and the PSC staff  entered  into a
settlement  agreement with respect to this proceeding.  The settlement agreement
is subject to PSC approval.  For information about the settlement  agreement and
changes  to  the  Company's  business,  see  "Liquidity  and  Capital  Resources
Competition  and  Restructuring  and PSC  Settlement  Agreement  " in Item 7 and
"Competitive Businesses," below.

      This report includes forward-looking  statements,  which are statements of
future  expectation  and  not  facts.  Words  such  as  "estimates,"  "expects,"
"anticipates,"   "plans,"  and  similar  expressions  identify   forward-looking
statements.  Actual results or developments  might differ  materially from those
included  in  the   forward-looking   statements  because  of  factors  such  as
competition and industry restructuring,  changes in economic conditions, changes
in  historical  weather  patterns,  changes in laws,  regulations  or regulatory
policies,  developments  in  legal or  public  policy  doctrines,  technological
developments and other presently unknown or unforeseen factors.


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INDUSTRY SEGMENTS

      In 1996,  electric,  gas and steam  operating  revenues were 79.6 percent,
14.6 percent and 5.8 percent, respectively, of the Company's operating revenues.
For information on operating  revenues,  expenses and income for the years ended
December 31,  1996,  1995 and 1994,  and assets at those dates,  relating to the
Company's  electric,  gas and  steam  operations,  see  Note J to the  financial
statements in Item 8. For information  about changes to the Company's  business,
see "Liquidity and Capital  Resources - Competition  and  Restructuring  and PSC
Settlement Agreement" in Item 7 and "Competitive Businesses," below.


ELECTRIC OPERATIONS

      ELECTRIC SALES.  Electric  operating revenues were $5.6 billion in 1996 or
79.6 percent of total Company operating revenues.  The percentages were 82.5 and
80.6,  respectively,  in the  two  preceding  years.  Electricity  sales  in the
Company's service area in 1996,  including usage by customers served by NYPA and
the New York  City and  Westchester  County  municipal  electric  agencies,  but
excluding  off-system  sales,  increased 0.8 percent from 1995, after increasing
0.7 percent and 2.0 percent,  respectively,  in the two preceding  years.  After
adjusting for  variations,  principally  weather and billing  days,  electricity
sales volume  increased 0.9 percent in 1996, 1.2 percent in 1995 and 1.5 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 occurred.

      In 1996,  79.8  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, 29.2 percent was to residential customers, 66.9 percent was to commercial
customers,  2.2  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  information  about the Company's  current
electric rate  agreement,  see "Liquidity and Capital  Resources - 1995 Electric
Rate  Agreement" in Item 7. For  information  about changes that will permit the
Company's  customers to choose alternative energy suppliers,  see "Liquidity and
Capital Resources - Competition and Restructuring and PSC Settlement  Agreement"
in Item 7.


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


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      The sources of electric  energy  generated and purchased  during the years
1992-1996 are shown below:

                                  1992     1993     1994     1995     1996

Generated:
  Fossil-Fueled* ...........      42.3%    35.5%    30.9%    30.1%    22.7%
  Nuclear (Indian Point 2) .      20.4%    14.8%    18.4%    10.8%    17.7%
Total Generated ............      62.7%    50.3%    49.3%    40.9%    40.4%

Firm Purchases:
  NYPA .....................       4.8%     6.0%     1.3%     1.3%     2.0%
  Hydro-Quebec .............       2.9%     4.3%     4.8%     5.8%     6.0%
  Non-Utility Generators ...       8.9%    11.9%    12.9%    29.9%    29.5%
Other Purchases* ...........      20.7%    27.5%    31.7%    22.1%    22.1%
Total Purchased ............      37.3%    49.7%    50.7%    59.1%    59.6%

Generated & Purchased ......       100%     100%     100%     100%     100%
-----
*  For 1996 and 1995, includes electricity generated for others. See "Gas
Conversions" and "Operating Statistics", below.

      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  divestiture  of the  Company's
generating  capacity,  see  "Liquidity  and Capital  Resources - PSC  Settlement
Agreement" in Item 7. For information about the Company's  purchases of electric
energy, see "NYPA",  "Hydro-Quebec",  "Non-Utility Generators",  "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 1996 one-hour peak
load in the Company's  service area (which  occurred on July 18, 1996) was 9,788
thousand  kilowatts  (MW).  The record  peak load for the  service  area,  which
occurred  on August 2,  1995 was  10,805  MW.  The 1996  peak load  included  an
estimated 8,158 MW for the Company's customers and 1,630 MW for NYPA's customers
and  municipal  electric  agency  customers.  The  1996  peak,  if  adjusted  to
historical design weather  conditions,  would have been 10,950 MW, 100 MW higher
than the peak in 1995 when similarly adjusted. The Company estimates that, under
design  weather  conditions,  the 1997  service  peak load  would be 11,050  MW,
including  9,300  MW for  the  Company's  customers.  "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 1996 totaled (before  outages) 13,635 MW, of
which 10,362 MW represented  net available  generating  capacity  (including the
capacity of NYPA's  Poletti and Indian  Point 3 units) and 3,273 MW  represented
net firm  purchases  by the  Company  and  NYPA.  The  Company  expects  to have
sufficient electric capacity available to meet the requirements of its customers
in 1997. For information about the Company's  capacity reserve margin,  see "New
York Power Pool", below.


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      For  information   about  the  Company's   generating,   transmission  and
distribution  facilities,  see "Electric  Facilities" in Item 2. For information
about  divestiture  of the Company's  generating  capacity,  see  "Liquidity and
Capital  Resources - PSC Settlement  Agreement" in Item 7. 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.

      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.


      NON-UTILITY   GENERATORS.   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 NUGs. The Federal Energy  Regulatory  Commission  (FERC) has
issued  rules  requiring  utilities  to  purchase  electricity  from  qualifying
facilities  at a price equal to the  purchasing  utility's  "avoided  cost." For
information about the Company's  contracts with NUGs, see "Liquidity and Capital
Resources - Electric  Capacity  Resources and Competition and  Restructuring and
PSC  Settlement  Agreement" in Item 7 and Note G to the financial  statements in
Item 8.



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                                       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 1996 and expects
to meet it in 1997. For  information  about a plan to restructure  the wholesale
electric  market  in New  York  State,  see  "Liquidity  and  Capital  Resources
Competition and Restructuring" in Item 7.


      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 1996, the Company,  for a fee,  generated  1,672,603
MWhrs of electric  energy (3.8  percent of the  electric  energy  generated  and
purchased by the Company) for others using as fuel gas that they  provided,  and
subsequently  purchased  1,553,764 MWhrs of such electric energy for sale to the
Company's customers.  In 1995, 3,159,047 MWhrs were so generated (7.0 percent of
the electric energy generated and purchased by the Company),  of which 2,666,837
MWhrs were subsequently purchased by the Company.



GAS OPERATIONS


      GAS  SALES.  Gas  operating  revenues  in 1996 were $1.0  billion  or 14.6
percent of total Company operating revenues. The percentages were 12.4 and 14.0,
respectively,  in the two preceding  years.  Gas sales volume to firm  customers
increased  8.9  percent  in 1996  from  the  1995  level.  After  adjusting  for
variations,  principally  weather,  firm gas  sales  volume  to these  customers
increased  1.9  percent.   Including  sales  to  interruptible   and  off-system
customers, actual sales volume increased 19.0 percent in 1996.



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      The Company sells gas to its firm gas customers at the Company's cost. The
Company shares with its firm gas customers net revenues (operating revenues less
the cost of gas purchased for resale) from  interruptible gas sales,  off-system
sales and other  "non-core"  transactions.  Regardless of whether the Company or
another  supplier sells the gas to customers in the Company's  service area, the
gas is distributed to the customers through the Company's system of distribution
mains and service  lines.  The customers pay the Company a fee  (reflecting  the
Company's  costs  and a rate of return on the  Company's  investment  in its gas
system) for  distributing the gas. For information  about the Company's  current
gas rate  agreement see  "Liquidity  and Capital  Resources - Gas and Steam Rate
Agreements" in Item 7. For Information  about the Company's gas facilities,  see
"Gas Facilities" in Item 2.

      All of the Company's 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),  became  eligible in 1996 to purchase  gas
directly  from  suppliers  other than the  Company.  In 1996,  100  large-volume
customers,  with a total usage of approximately 20,000,000 dekatherms per annum,
had contracts  enabling them to purchase gas from other  suppliers.  The Company
sold to these  customers 75 percent of the gas used by them. By the end of 1996,
12 smaller firm gas customers, with a total annual usage of approximately 17,200
dekatherms per annum, had aggregated their demand.  All of the gas used by these
smaller  customers  in  1997  is  expected  to  be  supplied  by  gas  marketers
unaffiliated with the Company.

      The Company enters into off-system sales  transactions such as releases of
pipeline capacity and bundled sales of gas and ancillary services.  Net revenues
from these transactions were $15.1 million in 1996,  compared to $2.5 million in
1995.

      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.


      GAS REQUIREMENTS.  Firm 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 71,400  thousand
dekatherms  (mdth) of gas during the 1996/97  winter heating season and that gas
available to the Company  would amount to 92,300 mdth.  For the 1997/98  winter,
the Company estimates that the requirements would amount to approximately 72,200
mdth and that the gas  available to the Company  would  amount to  approximately
92,300 mdth.  As of March 15, 1997,  the 1996/97  winter peak day sendout to the
Company's  customers  was 798 mdth,  which  occurred  on January 18,  1997.  The
Company estimates that, under the design criteria, the peak day requirements for
firm customers  during the 1997/98  winter season would amount to  approximately
862 mdth and expects that it would have  sufficient  gas available to meet these
requirements.



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                                       10






      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 sixteen 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.  The Company expects to have sufficient gas
supply to meet the requirements of its customers in 1997.



STEAM OPERATIONS


      STEAM SALES.  The Company  sells steam in Manhattan  south of 96th Street,
mostly to large office buildings, apartment houses and hospitals. In 1996, steam
operating  revenues were $405 million or 5.8 percent of total Company  operating
revenues. The percentages were 5.1 and 5.4,  respectively,  in the two preceding
years.  Steam sales  volume  increased  1.9 percent in 1996 from the 1995 level.
After adjusting for variations,  principally weather,  steam sales decreased 0.1
percent.  For information about the Company's current steam rate agreement,  see
"Liquidity and Capital Resources - Gas and Steam Rate Agreements" in Item 7.

      STEAM  SUPPLY.  47.3  percent of the steam sold by the Company in 1996 was
produced in the Company's electric generating  stations,  where it is first used
to  generate  electricity.  2.2 percent of the steam sold by the Company in 1996
was purchased from a NUG. The remainder was produced in the Company's steam-only
generating  units.  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 1996/97 (through March 15, 1997) occurred on January 13, 1997 when the
load reached 10.0 million pounds.  The Company  estimates that for the winter of
1997/98  the peak  demand of its steam  customers  would be  approximately  12.2
million pounds per hour under design criteria, which assume severe weather.

      On December 31, 1996,  the steam system had the  capability  of delivering
about 14.2  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 13.1 million pounds of
steam per hour in the 1997/98 winter.




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                                       11







COMPETITIVE BUSINESSES AND COMPETITION


      For  information  about  competition in the electricity and gas industries
and additional  information  about the Company's  plans to engage in competitive
businesses,  see "Liquidity and Capital Resources - Electric Capacity Resources,
Competition and Industry  Restructuring and PSC Settlement  Agreement" in Item 7
and "Gas Operations - Gas Sales," above.

      ProMark Energy, Inc. and Gramercy Development, Inc, each a wholly-owned
subsidiary of the Company, engage in competitive businesses.

      ProMark  was formed in 1993 to market gas and related  services.  In 1996,
the PSC eliminated its restriction  which had prohibited  ProMark from marketing
gas within the Company's gas service area. In March 1997,  the PSC authorized an
expansion of ProMark's business  activities that will permit ProMark to become a
full-service  provider of energy services  engaging in both wholesale and retail
sales of electricity and gas and related services.

      Gramercy  Development  was  formed  in  late  1996  to  invest  in  energy
infrastructure development projects and to market technical services.

      The financial statements in Item 8 include the accounts of the Company and
its wholly-owned subsidiaries (with intercompany  transactions  eliminated).  At
December  31,  1996,  the  Company's   investment  in  these   subsidiaries  was
approximately $16 million.  The results of operations of these subsidiaries have
not been material.



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.





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                                       12






FUEL SUPPLY


      GENERAL.  In  1996,  22.1  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 77.9 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 8.7 percent of the  electricity,  natural gas 43.0 percent,
nuclear  power 19.3  percent,  hydroelectric  power 6.0 percent,  and refuse 0.9
percent.  In 1996,  the Company  used oil to produce  63.1  percent,  and gas to
produce 34.7  percent,  of the steam  supplied to the Company's  customers.  The
remaining 2.2 percent was purchased by the Company from a NUG.

      A  comparison  of the cost,  in cents per million Btu, of fuel used by the
Company to generate electricity and steam (excluding  electricity  generated for
others as described under "Gas  Conversions,"  above) during the years 1992-1996
is shown below:
                   1992      1993      1994      1995      1996
Residual Oil ...... 345       352       316       316       441
Distillate Oil .... 501       499       467       399       465
Natural Gas ....... 285       288       255       253       324
Nuclear ...........  43        37        42        51        50
Weighted Average .. 232       243       206       223       255

      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 1996,  including the Company's shares of
generating capacity at Roseton and Bowline Point,  totaled 10.4 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  1997.  The Company
anticipates covering the balance of its 1997 requirements through new contracts,
exercise of existing contract options and purchases on the spot market.


      NATURAL GAS. During 1996, the Company burned  approximately 89,900 mdth of
gas  for  the  production  of  electricity  and  steam,   including  5,000  mdth
attributable  to the Company's  share of generating  capacity at the Roseton and
Bowline Point stations and 16,700 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 1997 for the  production of electricity
and steam for its customers.



<PAGE>
                                       13






      DISTILLATE OIL. The Company's  estimated 1997  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 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 and conversion provided under these contracts,  together
with that already  purchased,  will be sufficient  for the planned 1997 and 1999
refuelings of Indian Point 2.  Arrangements are expected to be completed in 1998
for the  additional  uranium  and  conversion  required  for the  expected  2001
refueling  of Indian  Point 2. The Company has  contracts  covering  most of its
expected  requirements for uranium  enrichment  services and all of its expected
requirements  for fuel  fabrication  services  through the  expiration of Indian
Point 2's operating license in 2013.

      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 refueling and  maintenance  outage is
scheduled to commence in May 1997.  Mid-cycle inspection and maintenance outages
may also be required.  An unscheduled Indian Point 2 outage commenced on January
25, 1997 and ended on March 15, 1997.

      See  "Nuclear  Decommissioning"  and  "Nuclear  Fuel"  in  Note  A to  the
financial statements in Item 8.

      The Company is one of eleven  utilities  participating  in a private spent
fuel  storage  initiative,   which  plans  to  license  and  build  an  interim,
commercial,  spent  nuclear fuel storage  facility by 2002.  The site  currently
under  consideration is on the Skull Valley Goshute Indian  Reservation in Utah.
Since  1995,  each  participant  has  contributed  approximately  $1 million for
engineering,  licensing  and  legal  studies  for the  preparation  of a license
submittal to the Nuclear  Regulatory  Commission  by the third  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.


<PAGE>
                                       14






      The Company disposes of low-level  radioactive  wastes (LLRW) generated at
Indian  Point at the  licensed  disposal  facility  located in  Barnwell,  South
Carolina. Under the 1985 Federal Low Level Radioactive Waste Amendments Act, New
York State was required by January 1996 to provide for permanent disposal of all
LLRW generated in the state.  New York State has not provided for such disposal.
The Company  expects that it will be able to provide for such storage of LLRW as
may be required until New York State  establishes a storage or disposal 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.

      For  information  about changes in regulation  affecting the Company,  see
"Liquidity and Capital Resources - Competition and Industry Restructuring and
PSC Settlement" in Item 7.

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

      New York State law requires electric and gas utilities to charge religious
organizations  rates that do not exceed those charged to residential  customers.
In  December  1994,  the Company and the New York  Attorney  General  executed a
settlement  under which the Company admitted no wrongdoing but agreed to provide
refunds to religious  organizations  that had been served under generally higher
commercial rates and transfer affected  customers to the appropriate rates. In a
related  matter,  seven  customers  have sued the  Company in the United  States
District  Court for the Southern  District of New York each claiming 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.  The
suit is entitled  Brownsville  Baptist Church,  et. al. v.  Consolidated  Edison
Company of New York, Inc.

      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.  The Energy  Planning  Board has announced that a new
plan will be issued during 1997.



<PAGE>
                                       15






ENVIRONMENTAL MATTERS AND RELATED LEGAL PROCEEDINGS

      GENERAL. During 1996, the Company's capital expenditures for environmental
protection  facilities and related studies were  approximately $45 million.  The
Company  estimates  that such  expenditures  will  amount to  approximately  $53
million  in 1997  and  $43  million  in  1998.  These  amounts  include  capital
expenditures  in 1997 and 1998 required to comply with the Federal Clean Air Act
Amendments of 1990 and a 1994 consent decree with the New York State  Department
of Environmental Conservation.  See "Liquidity and Capital Resources - Clean Air
Act Amendments" in Item 7 and "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.

      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  are  generated  in the  Company's  operations  or may be  present at
Company locations. Also, hazardous substances were 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.  For
information  about asbestos,  see  "Environmental  Matters - Asbestos Claims" in
Note F to the financial  statements in Item 8 and "Gramercy  Park" 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.  For  information  about  divestiture  of the  Company's  in-City  generating
capacity,  see "Liquidity and Capital  Resources - PSC Settlement  Agreement" in
Item 7.


<PAGE>
                                       16






      The flue gases  from oil  combustion  furnaces,  including  the  Company's
generating  stations,  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 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 1996,  the EPA issued an interim  final  report
regarding the study. The report contains no conclusions  concerning the need for
control of hazardous air pollutants from utility facilities.

      In  November  1996,  the EPA  proposed  new ozone and  particulate  matter
standards.  If the new standards are adopted,  the New York State  Department of
Environmental  Conservation  (DEC) will be required to develop an implementation
plan  acceptable to the EPA. The Company cannot predict  whether or in what form
new standards will be adopted.  If the proposed  ozone standard is adopted,  the
Company  does not  expect  that  compliance  with this  standard  would  require
additional  capital  expenditures in excess of the approximately $150 million of
capital expenditures  estimated to be required for compliance with the Clean Air
Act amendments of 1990.  See  "Liquidity  and Capital  Resources - Clean Air Act
Amendments" in Item 7. If the proposed  particulate  matter standard is adopted,
the  Company  expects  that  compliance  with  the new  standard  could  require
additional capital expenditures, the amount of which could be material.

      In March  1991,  the DEC  issued a notice  of  intent  to  prepare a draft
environmental  impact  statement  (DEIS)  concerning  draft DEC 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 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 would  reach their  "useful  design  lives" 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  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.

      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.


<PAGE>
                                       17






      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.  The Company
has  been  participating  with  the  DEC and  several  environmental  groups  in
reviewing  the initial  DEIS.  The review is expected to be  completed  in 1997,
after  which a revised and updated  DEIS will be  prepared  for public  comment.
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. In October 1996, the National  Academy of Science issued a
report concluding that "the current body of evidence does not show that exposure
to [EMF] presents a human health hazard." For additional  information about EMF,
see "Environmental  Matters - EMF" in Note F to the financial statements in Item
8.


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 15,801  employees on December 31,  1996.  For  information
about the  collective  bargaining  agreement  covering  about  two-thirds of the
Company's employees, see "Liquidity and Capital Resources - Collective
Bargaining Agreement " in Item 7.


RESEARCH AND DEVELOPMENT

      For information  about the Company's  research and development  costs, see
Note A to the financial statements in Item 8.

<PAGE>
                                       18




<TABLE>

OPERATING STATISTICS
=======================================================================================================================
<S>                                      <C>              <C>              <C>              <C>              <C>
Year Ended December 31                        1996          1995              1994             1993             1992
-----------------------------------------------------------------------------------------------------------------------
ELECTRIC Energy (MWhrs)

Generated (a) ........................   17,823,778       18,436,798       20,419,828       20,079,995       24,157,503
Purchased from Others (a) ............   26,178,042       26,700,594       21,036,437       19,813,654       14,360,373
Total Generated and Purchased ........   44,001,820       45,137,392       41,456,265       39,893,649       38,517,876
Less: Supplied without direct charge .           71               71               73               74               75
      Used by Company (b) ............      164,206          165,934          134,940          183,903          173,834
      Distribution losses and
            other variances ..........    2,716,235        2,977,547        2,762,315        2,863,828        2,781,046
Net Generated and Purchased ..........   41,121,308       41,993,840       38,558,937       36,845,844       35,562,921

Electric Energy Sold:
      Residential ....................   10,867,085       10,848,648       10,660,148       10,512,496        9,845,397
      Commercial and Industrial ......   25,725,502       25,492,489       25,511,974       25,118,125       24,680,600
      Railroads and Railways .........       47,004           47,482           47,289           49,542           50,934
      Public Authorities .............      564,363          569,749          554,753          560,836          542,358
Total Sales to Con Edison Customers      37,203,954       36,958,368       36,774,164       36,240,999       35,119,289
Off-System Sales (a) (c) .............    3,917,354        5,035,472        1,784,773          604,845          443,632
Total Electric Energy Sold ...........   41,121,308       41,993,840       38,558,937       36,845,844       35,562,921

Total Sales to Con Edison Customers      37,203,954       36,958,368       36,774,164       36,240,999       35,119,289
Delivery Service to NYPA
      Customers and Others ...........    8,816,873        8,855,790        8,773,155        8,441,624        8,187,292
Service for Municipal Agencies .......      617,293          456,728          413,893          361,854          287,489
Total Sales in Franchise Area ........   46,638,120       46,270,886       45,961,212       45,044,477       43,594,070


Average Annual kWhr Use Per
      Residential Customer (d) .......        4,184            4,188            4,136            4,104            3,872

Average Revenue Per kWhr Sold (cents):
      Residential (d) ................         16.5             16.1             15.8             16.0             15.0
      Commercial and Industrial (d) ..         12.9             12.5             12.2             12.6             12.0



(a) For 1996 and 1995,  amounts generated include 1,672,603 and 3,159,047 MWhrs,
    respectively,  generated  for others,  which is also  included in off-system
    sales. For 1996 and 1995,  amounts purchased include 1,553,764 and 2,666,837
    MWhrs, respectively, of such electric energy that was subsequently purchased
    by the Company. See "Electric Operations Gas Conversions", above.

(b) For 1995, 1993 and 1992,  electric energy used by the Company  includes 436,
    29,233 and 30,859 MWhrs,  respectively,  supplied to NYPA. For 1996 and 1994
    electric  energy  used  by  the  Company  includes  544  and  21,275  MWhrs,
    respectively, received from NYPA.

(c) For 1995, 1994, 1993 and 1992,  off-system sales include 2,825,  350, 2,142,
    and  52,929  MWhrs,  respectively,  which  were  sold to NYPA  and are  also
    included in the Delivery  Service to NYPA.  There were no such sales to NYPA
    in 1996.

(d) Includes Municipal Agency sales.


<PAGE>
                                       19





OPERATING STATISTICS
=======================================================================================================================
<S>                                       <C>              <C>             <C>            <C>              <C>
Year Ended December 31                        1996            1995            1994             1993             1992
-----------------------------------------------------------------------------------------------------------------------


GAS (Dth) (a)

Purchased (b) ..........................  219,439,813       217,268,986    208,328,267     214,719,241      221,181,200
Storage - net change ...................   (4,032,224)        9,469,767     (4,410,363)        222,559          752,561
     Used as boiler fuel  at Electric
      and Steam Stations (b) ...........  (84,849,049)     (110,761,124)   (92,680,221)   (108,153,436)    (116,951,577)
Gas Purchased for Resale ...............  130,558,540       115,977,629    111,237,683     106,788,364      104,982,184

Less: Gas used by Company ..............      272,040           237,688        221,715         203,793          153,537
      Off-System Sales & NYPA (c) ......   11,023,023         4,887,971          --              --               --
      Distribution losses
           and other variances .........      176,930         4,654,832      2,443,486       3,998,234        3,856,836
Total Sales to Con Edison Customers ....  119,086,547       106,197,138    108,572,482     102,586,337      100,971,811

Gas Sold (a)
Firm Sales:
      Residential ......................   56,590,018        51,702,329     53,981,416      52,624,331       52,626,406
      General ..........................   42,190,091        39,021,997     39,365,003      37,214,994       36,656,433
      Total Firm Sales .................   98,780,109        90,724,326     93,346,419      89,839,325       89,282,839
Interruptible Sales ....................   20,306,438        15,472,812     15,226,063      12,747,012       11,688,972
Total Sales to Con Edison Customers ....  119,086,547       106,197,138    108,572,482     102,586,337      100,971,811
Transportation of Customer-Owned Gas:
      NYPA .............................    4,966,983        24,972,796     14,546,325      15,965,084       19,892,008
      Other ............................    5,011,124         5,388,393      3,823,176       4,926,565        5,556,433
Off-System Sales .......................   11,293,425         3,376,375         --              --                --
Total Sales and Transportation .........  140,358,079       139,934,702    126,941,983     123,477,986      126,420,252


Average Revenue Per Dth Sold (a):
      Residential ......................       $10.00            $ 9.43         $ 9.85          $ 9.27           $ 8.41
      General ..........................       $ 7.15            $ 6.38         $ 7.05          $ 6.71           $ 6.03



STEAM Sold (Mlbs): .....................   29,995,762        29,425,780     30,685,155      29,394,335       29,381,922

Average Revenue per Mlbs Sold ..........       $13.34            $11.35         $11.10          $11.06           $10.63


CUSTOMERS - Average for Year
Electric ...............................    3,001,870         2,994,447      2,980,026       2,964,716        2,950,614
Gas ....................................    1,035,528         1,034,784      1,031,675       1,028,048        1,026,546
Steam ..................................        1,932             1,945          1,964           1,973            1,970




(a) Does not include amounts for the Company's gas marketing subsidiary.  See
    "Competitive Businesses and Competition," above.

(b) For  1996 and  1995,  gas  used as  boiler  fuel  includes  16,739,188  and
    31,706,551 Dth, respectively, provided by others. See "Electric Operations -
    Gas Conversions," above.

(c) For 1996 and 1995,  includes  173,388 and 1,305,730 Dth,  respectively,  for
    balancing transactions with NYPA.


</TABLE>



<PAGE>
                                       20






ITEM 2.     PROPERTIES

      At December 31, 1996, the capitalized cost of the Company's utility plant,
net of accumulated  depreciation,  (and excluding $101.5 million of nuclear fuel
assemblies) was as follows:
                              Net Capitalized Cost               Percentage of
Classification                   (millions of dollars)         Net Utility Plant

In Service:
      Electric:
           Generation .......... $   1,696.1                        15%
           Transmission ........     1,127.3                        10%
           Distribution ........     5,237.7                        48%
      Gas ......................     1,275.5                        12%
      Steam ....................       445.0                         4%
      Common ...................       837.1                         8%
Held For Future Use ............        14.8                        --
Construction Work in Progress ..       332.3                         3%
Net Utility Plant .............. $  10,965.8                       100%


ELECTRIC FACILITIES


      GENERATING  FACILITIES.  As shown in the following  table, at December 31,
1996, the Company's net maximum  generating  capacity (on a summer rating basis)
was 8,333 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. For
information  about  divestiture  of  the  Company's  generating  capacity,   see
"Liquidity and Capital Resources - PSC Settlement Agreement" in Item 7.

Generating              Net Generating Capacity       Percentage of Electric
   Stations               at December 31, 1996        Energy Generated and
                        (Megawatts-Summer Rating)     Purchased in 1996*
Fossil-Fueled:
   Ravenswood (3 Units) ......   1,742                       7.9%
   Astoria (3 Units) .........   1,075                       7.1%
   Arthur Kill (2 Units) .....     826                       1.6%
   East River (2 Units) ......     300                       0.7%
   Bowline Point (2 Units)
        - two-thirds interest      808                       1.3%
   Roseton (2 Units)
        - 40% interest .......     480                       1.4%
   Other (4 Units) ...........     231                       1.6%
      Subtotal ...............   5,462                      21.6%
Nuclear - Indian Point .......     931                      17.7%
Gas Turbines (39 Units) ......   1,940                       1.1%
      Total ..................   8,333                      40.4%

* Includes electricity generated for others. See "Electric Operations - Gas
Conversions" in Item 1.


<PAGE>
                                       21





      The  Company's  generating  stations are located in New York City with the
exception of the Indian Point nuclear 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  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 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 1997.


      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, 1996, 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, 1996,  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 1996 one-hour  peak load in the  Company's  service area was 9,788
MW, of which 8,575 MW was for use within the City. The record one-hour peak load
in the Company's  service area, which occurred in August 1995, 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.


<PAGE>
                                       22






      DISTRIBUTION FACILITIES. The Company owns various distribution substations
and facilities  located  throughout  New York City and  Westchester  County.  At
December  31,  1996,  the  Company's  distribution  system had 294  distribution
substations,  with a transformer  capacity of 20,065  megavolt  amperes,  32,307
miles  of  overhead   distribution   lines  and  87,001  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 360,700 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 23 1/3 percent
owned by the Company.



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.




<PAGE>
                                       23






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 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  contaminated  leachate that has accumulated in the site's waste
burial  trenches,  the installation of an impervious cover over the waste burial
trench area of the site, and the construction of a  trench/leachate  groundwater
monitoring  system,  erosion  controls and storm water drainage  systems in that
area.  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
(including  the Company),  large federal  agency PRPs and Kentucky  entered into
consent  decrees with respect to the funding and  implementation  of the cleanup
program.  Under the consent  decrees,  which in April 1996 were  approved by the
United States  District  Court for the Eastern  District of Kentucky,  the large
private party PRPs will  implement  phase one of the program and any  corrective
actions required during the first 10 years following  completion of phase one to
meet the  performance  standards  established in the ROD, and 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 private  party PRPs will  construct the barriers and share the cost of
that work with the large  federal  agency PRPs and  Kentucky.  The large private
party 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  during the ten-year period  following  completion of
the phase one  program,  the  Company  would be  obligated  to pay an  estimated
$10,000  to  $100,000  depending  on the size  and the  number  of the  barriers
required by the EPA.


<PAGE>
                                       24






      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  had occurred on a portion of the site.
Elevated  concentrations  of PCBs and various organic  compounds and metals were
detected in the soil and PCBs,  organic  compounds and various  metals were also
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, which are
in progress,  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 had reason to believe  that the Company was a supplier
of scrap  transformers  to  Metal  Bank of  America  Inc.'s  recycling  sites in
Philadelphia  during the late 1960s and thereafter.  One of the sites was placed
on the EPA's  national  priority  list under  Superfund in 1983 as a result of a
suspected leak in a storage tank containing  PCBs. The EPA alleged that PCBs had
been  found in the soil and  groundwater  at the site and in the  sediment  from
areas of a tidal mudflat and the Delaware River along the site's shoreline.  The
Company  provided the EPA with  documents  which  indicate that the Company sold
approximately 80 scrap transformers to a broker who, in turn,  delivered them to
the site and that the Company sold an additional 46 scrap  transformers to Metal
Bank (which may have salvaged them at 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,  among other
things,   the  removal   and   disposal   of  PCBs  and   polynuclear   aromatic
hydrocarbon-contaminated  sediments  in the areas of the tidal  mudflat  and the
Delaware River along the site's shoreline, the construction of a sheet pile wall
along the site's  shoreline,  the removal and  off-site  disposal of soil in the
southern portion of the site that contains 25 parts per million (ppm) or more of
PCBs and/or 10,000 ppm or more of total petroleum  hydrocarbons  (TPH),  and the
removal and off-site  disposal of soil that contains more than 10 ppm of PCBs in
the northern portion of the site. 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.




<PAGE>
                                       25






      NARROWSBURG  SITE. In 1987, the New York State Attorney  General  notified
the Company that he had 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 Superfund  National  Priorities List.  Company records indicate that drums
containing  waste oil were shipped from its Indian Point nuclear  station to the
Cortese  landfill for  disposal.  Before  notifying  the  Company,  the Attorney
General  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  paid  $114,485
toward the cost of the site environmental studies conducted by SCA and agreed to
pay 6 percent  of the first  $25  million  of  remedial  costs at the site.  SCA
Services has agreed to indemnify  the Company for any other  remedial  costs and
natural  resource  damages  that it has to pay.  The EPA has  selected a cleanup
program for the site that is estimated to cost $12 million. 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 approved by the United
States District Court for the Southern District of New York. Cleanup work at the
site is now in progress.


      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
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 0.8 to 1.7  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 releases 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, which has been completed, cost $10 million.



<PAGE>
                                       26






      HELEN  KRAMER  LANDFILL  SITE.  In  September  1991,  Orange and  Rockland
Utilities,  Inc.  (O&R) was served with a  third-party  complaint in a Superfund
cost recovery  contribution action for the Helen Kramer Landfill Site in Mantau,
New Jersey.  The  third-party  plaintiffs  are site PRPs that were sued for site
cleanup costs by the State of New Jersey. The complaint, which is pending before
the United States  District Court for the District of New Jersey,  alleges 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.  The  third-party
plaintiffs have offered to settle with O&R and other third-party defendants.  If
the  settlement  is approved by the district  court,  O&R would pay $15,000 to a
site  trust fund and the  third-party  plaintiffs  would  dismiss  their  action
against  O&R and  indemnify  O&R from  claims  for site  cleanup  costs by other
parties.


      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  57.5-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.

      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  designated  site PRPs to fund a $1.5 million
remedial  investigation  and feasibility  study for the site. The Company joined
the PRP  Group  formed  for the site 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 required the
Company  and the other  site PRPs 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.


<PAGE>
                                       27






      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.


      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  sought $24 million for personal injuries and property
damages,  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  and legal fees. In December  1994, the
court  dismissed  plaintiffs  claims  for  property  damage,  including  loss of
business.  Pretrial discovery on the remaining claims is continuing.  In October
1996, the Company filed a motion to dismiss the personal injury claims.


      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 and a partially-occupied, seven-story
building -- 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 has developed a preliminary  list  indicating  that  approximately
16.9 million  pounds of  PCB-contaminated  oil,  equipment  and  materials  were
shipped  to the  sites.  The  Company  has  informed  the EPA  that  it  shipped
approximately  2.8 million pounds of waste to the sites.  The EPA has identified
over 700 parties that shipped  waste to the sites,  including  federal  agencies
which,  based on  responses  to the  EPA's  information  request,  appear  to be
responsible for approximately 7 million pounds of the waste.
EPA is continuing to search for additional PRPs.


<PAGE>
                                       28






      In September  1996,  the Company  joined a PRP steering  committee that is
conducting  studies at the sites under an EPA consent  order and  negotiating  a
cost  sharing   agreement  with  federal  agency  PRPs.   Based  on  preliminary
information,  the  Company  currently  believes  that its share of the study and
remediation costs could exceed $5 million.


      PELHAM  MANOR  SITE.  Prior  to  1968,  the  Company  and its  predecessor
companies  operated a manufactured  gas plant on a site located in Pelham Manor,
Westchester  County,  which  is  now  used  for  a  shopping  center.  Soil  and
groundwater  tests by the current  owners and lessees  indicate  the presence of
hazardous substances which are associated with the manufactured gas 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.  The site  lessee  and the DEC are  negotiating  the  scope of the site
studies, which will be funded in major part by the Company.


      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 in Queens,  New York,  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.  A
portion of the investigation has been completed and reports thereon,  indicating
PCB-contamination  of portions of the site,  have been  submitted to the DEC and
the New York State Department of Health for the determination of the remediation
action that may be required. Depending on the remediation required, the costs of
remediation could be material.


      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  operated a  manufactured  gas plant at that  location  prior to the
1940's.  The Company has  conducted  preliminary  sampling at the site and found
coal tar beneath the areas  formerly  occupied  by the  manufactured  gas plant.
Material closely  resembling the coal tar at the site has also been found in the
Hudson River along the bulkhead of an asphalt plant located between the site and
the river and beneath  portions of the asphalt plant  property.  The Company has
assumed  responsibility  for  maintaining a boom in the river around the area of
bulkhead and will develop a cleanup program for the coal tar contamination under
an  agreement  with the DEC.  The cost of the cleanup  program  could  exceed $8
million if the DEC  requires the Company to excavate all of the coal tar present
on the site.


<PAGE>
                                       29






      PORT REFINERY SITE. The EPA notified the Company by letter,  dated October
21, 1996,  that it is a PRP for the Port Refinery  Superfund  Site in Rye Brook,
NY.  According  to the  EPA,  Port  Refinery  Company  used  the  site  for  the
reprocessing and repackaging of mercury and caused extensive contamination which
the EPA has cleaned up at a cost of approximately  $4.5 million.  In its letter,
the EPA  demands  reimbursement  of its costs from the  Company and the 58 other
site PRPs that the EPA has  identified.  Based on the documents  provided by the
EPA, it appears that the Company  shipped 60 pounds of mercury to Port Refinery.
In January 1997, the Company entered into a consent decree under which it agreed
to pay approximately  $2,000 as its share of the EPA's costs. The consent decree
will not become  effective until it is published for public comment and approved
by the United States District Court for the Southern District of New York.



TOXIC SUBSTANCES CONTROL ACT

      In November 1994, BCF Oil Refining,  Inc., a processor and refiner of used
oil  products  and waste  containing  oil,  brought  suit in the  United  States
District  Court for the  Southern  District of New York  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 sought  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.  In February
1997,  the court  dismissed 24 of BCF's 25 claims and the Company filed a motion
asking the court to dismiss the remaining  claim.  This suit is entitled BCF Oil
Refining, Inc. v. Consolidated Edison Company of New York, Inc., et. al.


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.  In April 1995, the Company
was  sentenced to a fine of $500,000 and to three years  probation  for criminal
acts  relating to the  reporting of the release of asbestos  from the steam main
explosion.   During  the  probation  period,   the  Company's   compliance  with
environmental laws is being 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.



<PAGE>
                                       30






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.

      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 joint  petition  for  review  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>
                                       31






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,
1997, 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.





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


Eugene R. McGrath - 55             9/90 to present - Chairman of the Board,
 Chairman of the Board,              President, Chief Executive Officer and
 President,                          Trustee
 Chief Executive Officer,          2/89 to 8/90 - President, Chief Operating
 and Trustee;                        Officer and Trustee
 9/1/78                           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

J. Michael Evans - 51              7/95 to present - Executive Vice President
  Executive Vice President  -        - Customer Service
  Customer Service;                4/95 to 6/95 - Executive Vice President
  9/1/91                           9/91 to 3/95 - Executive Vice President -
                                     Central Operations

Charles F. Soutar - 60             7/95 to present - Executive Vice President -
  Executive Vice President -         Central Services
  Central Services;                2/89 to 6/95 - Executive Vice President -
  9/1/77                             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 - 54               4/95 to present - Senior Vice President -
  Senior Vice President -            Central Operations
  Central Operations;             12/94 to 3/95 - Senior Vice President
  8/1/79                           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, System Operations and
                                     Technical Services
                                   8/79 to 6/80 - Vice President- Central
                                     Substation and   System Operations


<PAGE>
                                       32





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

Joan S. Freilich - 55                 7/96 to present - Senior Vice President
  Senior Vice President and Chief       and Chief Financial  Officer
  Financial Officer;                  9/94 to 6/96 - Vice President, Controller
  12/1/90                               and Chief Accounting Officer
                                      7/92 to 8/94 - Vice President and
                                        Controller
                                     12/90 to 6/92 - Vice President - Corporate
                                        Planning

Mary Jane  McCartney - 48            10/93 to present - Senior Vice  President
  Senior Vice President - Gas           Gas  Operations
  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. - 59             1/96 to present - Senior Vice President
  Senior Vice President and             and General Counsel
  General Counsel;                    4/87 to 12/95 - Vice President and
  1/1/96                                Associate General Counsel, ITT
                                        Corporation

Horace S. Webb - 56                   9/92 to present - Senior Vice President -
  Senior Vice 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 - 59               6/89 to present - Secretary and Associate
  Secretary and Associate General       General Counsel
  Counsel;                            1/74 to 5/89 - Secretary and Assistant
  1/7/74                                General Counsel

Hyman  Schoenblum  - 48               3/97 to  present - Vice  President  and
  Vice  President  and  Treasurer;      Treasurer
  3/1/97                              6/96 to 2/97 -  Director - Financial
                                        Restructuring
                                     11/93 to 5/96 - Director - Corporate
                                        Planning
                                      7/81 to 10/93 - Assistant Controller

Lawrence F. Travaglia - 58            3/93 to present - General Auditor
  General Auditor; 3/1/93             10/80 to 2/93 - Assistant Treasurer

John A. Arceri - 54                   6/95 to present - Vice President - Energy
  Vice President - Energy               Services
  Services;                          10/93 to 5/95 - Assistant Vice President -
  6/1/95                                Gas Business Development
                                      3/90 to 9/93 - Assistant Vice President -
                                        Electrical Distribution

Robert A. Bell - 63                   6/81 to present - Vice President -
  Vice President Research &             Research & Development
  Development;
  6/1/81



<PAGE>
                                       33





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

Kevin Burke - 46                      3/93 to present - Vice President -
  Vice President - Corporate            Corporate Planning
  Planning;                           3/90 to 2/93 - Vice President - Brooklyn
  12/1/87                               Customer Service
                                     12/87 to 2/90 - Vice President -
                                        Construction

John F. Cioffi     - 63               3/97 to present - Vice President and
  Vice President and Controller;         Controller
  7/1/92                             10/96 to 2/97 - Vice President, Treasurer
                                         & Controller
                                      7/96 to 9/96 - Vice President & Controller
                                      7/92 to 6/96 - Treasurer
                                      6/87 to 6/92 - Assistant Vice President

V.Richard  Conforti  - 58             8/96 to  present - Vice  President
  Vice  President - Transportation      Transportation & Stores
  & Stores;                           7/92 to 7/96 - Assistant Vice President -
  8/1/96                                Gas Operations
                                      4/91 to 6/92 - General Manager- Gas
                                        Operations -    Manhattan

Richard P. Cowie - 50                 3/94 to present - Vice President -
  Vice President - Employee             Employee Relations
  Relations;                          2/91 to 2/94 - Director - Central Customer
  3/1/94                                Service


Charles J. Durkin, Jr. - 53          12/93 to present - Vice President - Fossil
  Vice President - Fossil Power;        Power
  9/1/82                              1/88 to 12/93 - Vice President -
                                        Engineering
                                      9/82 to 12/87 - Vice President - System
                                        and Transmission Operations

Robert F. Crane - 60                  1/97 to present - Vice President - Gas
  Vice  President - Gas  Operations     Operations
   12/1/82                            3/94 to 1/97 - Vice President -
                                        Fuel Supply
                                     10/93 to 2/94 - Vice President -
                                        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

Vincent J. D'Amelio - 55              2/97 to present - Vice President - Staten
  Vice President - Staten Island        Island Customer Service
  Customer Service;                   4/88 to 1/97 - Director - Customer Service
  2/1/97                                Sprint Communications Company

George J. Delaney - 61                2/96 to present - Vice President - Central
  Vice President - Central              Services
  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


<PAGE>
                                       34





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


Robert W. Donohue, Jr. - 54         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

Jacob Feinstein - 53                4/91 to present - Vice President
  Vice President - System             - System & Transmission Operations
  Transmission Operations;
  4/1/91

David F.  Gedris  - 48              2/96 to  present  - Vice  President  -
 Vice President                       Westchester Customer Service
 - Westchester  Customer Service    2/94 to 1/96 - Vice President - Mantenance
   2/1/94                             and Construction
                                    7/92 to 1/94 - Assistant Vice President -
                                      Power Generation Maintenance
                                    3/90 to 6/92 - Assistant Vice President -
                                      Steam Operations

Garrett W. Groscup - 56             6/95 to present - Vice President - Brooklyn
  Vice President                      Customer Service
  - Brooklyn Customer Service;      2/94 to 5/95 - Vice President - Energy
  12/1/82                             Services
                                    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 - 51             2/97 to present - Vice President - Energy
 Vice President                       Management
 - Energy Management;               2/89 to 1/97 - Vice President - Planning and
  2/1/89                              Inter-Utility Affairs

Paul H. Kinkel - 52                2/96 to present - Vice President
 Vice President-                     Maintenance and Construction
 Maintenance and Construction;    12/93 to 2/96 - Vice President- Engineering
 5/24/83                          12/87 to 12/93 - Vice President - Fossil
                                     Power
                                   5/83 to 11/87 - Vice President - Construction

M. Peter Lanahan - 52              8/96 to present - Vice President -
  Vice President                     Environment, Health and Safety
  - Environment, Health            5/95 to 8/96 - Vice President - Environmental
  and Safety;                        Affairs
  5/1/95                           1/91 to 4/95 - Manager, General Electric
                                     Company


<PAGE>
                                       35





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


Richard J. Morgan - 61             12/96 to present - Vice  President - Steam
 Vice President  - Steam              Operations
  Operations;                       7/92 to 11/96 - Assistant  Vice  President -
  12/1/96                             Steam Operations

John A. Nutant - 61                 2/94 to present - Vice President - Manhattan
  Vice President - Manhattan          Customer Service;
  Customer Service;                 7/92 to 1/94 - Vice President - Queens
  5/27/80                             Customer Service
                                    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 - 49               3/94 to present - Vice President
  Vice President - Information        - Information Resources
  Resources;                        6/89 to 2/94 - Assistant Vice President -
  3/1/94                              - Employee Relations

Stephen E. Quinn - 50               9/94 to present - Vice  President - Nuclear
 Vice President - Nuclear Power;      Power
 9/1/94                             8/88 to 8/94 - General Manager - Nuclear
                                      Power Generation

Edwin W. Scott - 58                 6/89 to present - Vice President and Deputy
  Vice President and Deputy           General Counsel
  General Counsel;
  6/1/89

Minto L. Soares - 60                6/91 to present - Vice President - Bronx
  Vice President - Bronx              Customer Service
  Customer Service;
  6/1/91

Alfred R.  Wassler  - 52            8/96 to  present - Vice  President  -
  Vice  President - Purchasing;       Purchasing
  8/15/80                           3/94  to  8/96  -  Vice  President  -
                                      Purchasing, Transportation and Stores
                                    7/92 to 2/94 - Vice President - Purchasing
                                    8/80 to 6/92 - Treasurer








<PAGE>
                                       36





                                   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.

MARKET PRICE RANGE IN CONSOLIDATED REPORTING SYSTEM AND DIVIDENDS PAID ON
COMMON STOCK

                              1996                          1995

---------------------------------------------------------------------------
                                 Dividends                        Dividends
                 High      Low        Paid        High     Low         Paid

1st Quarter     $34-3/4  $30-7/8      $.52      $28-7/8   $25-1/2      $.51
2nd Quarter      32-3/8   27-3/8       .52       30-7/8    27           .51
3rd Quarter      29-5/8   25-7/8       .52       30-5/8    27-7/8       .51
4th Quarter      30-5/8   27-1/2       .52       32-1/4    28-3/8       .51

      As of January  31,  1997 there  were  143,820  holders of record of common
stock.

      On January 28,  1997,  the Board of  Trustees  of the  Company  declared a
quarterly  dividend of 52-1/2  cents per share of Common Stock which was paid on
March 15, 1997 to holders of record on February 19, 1997.


ITEM 6.  SELECTED FINANCIAL DATA

<TABLE>
Year Ended December 31             1996        1995      1994      1993       1992
------------------------------------------------------------------------------------
 (Millions of Dollars)
<S>                            <C>        <C>        <C>        <C>        <C>

Operating revenues ........... $ 6,959.7  $ 6,536.9  $ 6,373.1  $ 6,265.4  $ 5,932.9
Purchased power ..............   1,272.9    1,107.2      787.5      812.6      606.8
Fuel .........................     573.3      504.1      567.8      605.2      710.3
Gas purchased for resale .....     418.3      259.8      341.2      289.7      245.2
Operating income .............   1,013.6    1,041.4    1,036.2      951.1      880.4
Net income for common stock ..     688.2      688.3      698.7      622.9      567.7
Total assets .................  14,057.2   13,949.9   13,728.4   13,257.4   11,596.1
Long-term obligations
      Long-term debt .........   4,238.6    3,917.2    4,030.5    3,643.9    3,493.6
      Capitalized leases .....      42.7       45.3       47.8       50.4       52.9
      Preferred stock subject
      to mandatory
      redemption .............      84.6      100.0      100.0      100.0      100.0
Common shareholders' equity ..   5,727.6    5,522.7    5,313.0    5,068.5    4,886.9
Per common share:
      Net income .............     $2.93      $2.93      $2.98      $2.66      $2.46
      Cash dividends .........     $2.08      $2.04      $2.00      $1.94      $1.90

Average common shares
outstanding (millions) .......     235.0      234.9      234.8      234.0      231.1

</TABLE>


<PAGE>
                                       37





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 $106.9  million at December 31, 1996
compared with $342.3 million at December 31, 1995 and $245.2 million at December
31, 1994. The Company's cash balances  reflect,  among other things,  the timing
and amounts of external financing.

In December  1996 the Company  issued $150  million of five-year  floating  rate
debentures,  the  interest  rate on which is reset  quarterly.  A portion of the
proceeds  was used in that month to retire at  maturity  the $75  million  5.90%
Series DD mortgage bonds.

The  January  1996  retirement  at  maturity  of the $100  million  5% Series CC
mortgage bonds and the December 1995 redemption,  in advance of maturity, of the
$27.4 million of 9.70%  debentures were funded from cash balances.  In July 1995
the Company issued $100 million 10-year 6-5/8% debentures.

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 March  1996 the  Company  refunded  $317  million  of  certain  series of its
preferred  stock with the proceeds  from the issuance of $275 million of 35-year
7-3/4% subordinated  deferrable interest debentures (interest payments on which,
unlike  preferred stock  dividends,  are tax deductible) and $25 million of cash
balances. The net gain on this transaction was offset by an additional provision
for  depreciation.  See  Note B to the  financial  statements.  In May  1996 the
Company issued $100 million of 30-year 7-3/4% debentures,  the proceeds of which
were used in June 1996 to redeem,  in advance of maturity,  $95.3 million of its
9-3/8%  debentures.  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, in advance of maturity, a like amount of outstanding 9% tax-exempt debt.

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.
At such times the Company has borrowed from banks for short periods.

For 1997 the  Company  has  arranged  for bank credit  lines  amounting  to $150
million.  Borrowings  under the credit lines would bear  interest at  prevailing
market rates.

Customer  accounts  receivable,   less  allowance  for  uncollectible  accounts,
amounted to $544.0  million,  $497.2  million and $440.5 million at December 31,
1996,  1995 and 1994,  respectively.  The increase at year-end  1996 compared to
year-end 1995 is primarily  attributable  to higher fuel  billings.  In terms of
equivalent days of revenue outstanding, these amounts represented 28.6, 27.6 and
27.1 days, respectively.

Regulatory  accounts  receivable  recoverable  from customers  amounted to $45.4
million  and  $26.3  million  at  December  31,  1996  and  1994,  respectively.
Regulatory  accounts receivable at December 31, 1995 amounted to a net credit to
be  refunded  to  customers  of  $6.5  million.  See  Note  A to  the  financial
statements.



















The following is a summary of the balances and activity in  regulatory  accounts
receivable in 1996:


                                                             1996
                              Balance                  Recoveries       Balance
                             Dec. 31,      1996              from       Dec. 31,
(Millions of Dollars)           1995*    Accruals*      Customers**        1996*

Modified ERAM                 $(37.7)     $10.1          $28.0              $ .4
Electric Incentives
    Enlightened Energy
    program                     19.7       24.2          (14.8)             29.1
    Customer service             4.0        6.1           (4.6)              5.5
    Fuel and purchased
    power                        1.9       24.9          (23.3)              3.5
Gas Incentives
    System improvement           4.6        6.5           (6.2)              4.9
    Customer service             1.0        2.7           (1.7)              2.0
Total                         $ (6.5)     $74.5         ($22.6)            $45.4
*  Negative amounts are refundable; positive amounts recoverable
**Negative amounts were recovered; positive amounts refunded.

<PAGE>
                                       38




The components of the balance in regulatory  accounts receivable at December 31,
1996 are recoverable from customers during 1997 and 1998 under the 1995 electric
rate  agreement  and 1994 and 1997 gas rate  agreements  discussed  below.  See,
however, "PSC Settlement Agreement."

Deferred charges for Enlightened Energy  (demand-side  management) program costs
amounted to $133.7  million,  $144.3  million and $170.2 million at December 31,
1996, 1995 and 1994,  respectively.  These costs are recoverable  from customers
under the 1992 and 1995 electric rate agreements  discussed below. See, however,
"PSC Settlement Agreement."

The Company's  earnings include an allowance for funds used during  construction
which, as a percent of net income for common stock, was 0.7 percent, 0.8 percent
and 1.7 percent in 1996, 1995 and 1994, respectively.

Interest  coverage on the SEC book basis was 4.18, 4.20 and 4.58 times for 1996,
1995 and 1994, respectively. The decline in interest coverage in 1995 was due to
lower earnings and higher  interest  charges.  The Company's  interest  coverage
continues to be high compared with the electric utility industry generally.

The  Company's  unsecured  debentures  and  tax-exempt  debt  (which,  after the
December 1996  retirement at maturity of the last series of the Company's  first
mortgage bonds,  are the Company's  senior debt securities) are rated A1, A+ and
AA- by Moody's Investor Service  (Moody's),  Standard and Poor's (S&P) and Fitch
Investors Service, respectively. The Company's subordinated debentures are rated
A2 by Moody's and A by S&P.

Cash  flows  from  operating  activities  for years  1994  through  1996 were as
follows:

(Millions of Dollars)                     1996      1995      1994
Net cash flows from
     operating activities               $1,107    $1,276    $1,250
Less: Dividends on
   common and  preferred stock             511       515       505
Net after dividends                     $  596    $  761    $  745

Net  cash  flows  in 1996  were  lower  than in 1995  principally  due to  lower
incentive billings and higher costs for recoverable fuel and gas in storage. Net
cash  flows in 1996 were  favorably  affected  by  incentive  billings  of $50.6
million,  offset by the return to customers of $28 million of revenues under the
ERAM.  Net cash flows in 1995 were favorably  affected by incentive  billings of
$116.5  million,  offset by the return to  customers  of $54 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 related amounts  reflected in rates. See the table on the previous page for
balances in regulatory accounts receivable at December 31, 1996 recoverable from
customers in future periods.


Capital Requirements

The following table compares the Company's  capital  requirements  for the years
1994 through 1996 and estimated amounts for 1997 and 1998:

(Millions of Dollars)           1998       1997      1996     1995      1994

Construction expenditures       $622       $660      $675     $693     $ 758
Enlightened Energy program
    costs less recoveries (a)    (52)       (19)      (11)     (26)       30
Power contract termination
    costs - net (a)              (12)       (47)      (31)     (55)       62
Nuclear decommissioning
    trust (b)                     21         21        21       19        15
Nuclear fuel                      57         15        49       13        47
Investment in subsidiaries        52         77         7        2         7
Subtotal                         688        707       710      646       919
Retirement of long term debt
    and preferred stock (c)      200        106       184       11       134
Total                           $888       $813      $894     $657    $1,053

(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 1998, see Note B to the financial statements.

Capital  requirements  shown above for 1996 were met from  internally  generated
funds and external  debt  financings  of $150  million.  The Company  expects to
finance its capital  requirements  for 1997 and 1998,  including $306 million of
maturing securities,  from internally generated funds and external financings of
about $300 million, most, if not all, of which would be debt issues. In 1997 and
1998 the  Company  may,  from  time to time,  make  short-term  borrowings.  The
estimates for 1997 and 1998 do not reflect the  settlement  agreement  discussed
under "PSC Settlement Agreement." The Company is reviewing its capital structure
in the light of the Settlement  Agreement,  and these  estimates may change as a
result  of  this  review.  In  addition,  these  estimates  are  forward-looking
statements.  They are  statements of future  expectation  and not facts.  Actual
results might differ  materially from those estimated because of factors such as
the  continuing   development  of  competition   and  related   rule-making  and
legislation,  weather variations,  economic conditions, changes in public policy
and other presently unknown or unforeseen factors.



<PAGE>
                                       39



Electric Capacity Resources

Electric peak load in the Company's service area, adjusted for historical design
weather  conditions,  grew by 100  megawatts  (MW) (0.9  percent) in 1996.  This
growth was due primarily to the improving  local economy during 1996. The growth
in peak load has been  mitigated by the Company's  Enlightened  Energy  program,
introduced  in 1990,  which has  helped the  Company's  customers  purchase  and
install  energy-efficient  equipment and  encourages the efficient use of energy
resources.

In  response to federal  and state  regulatory  policies  and  requirements  for
utilities to contract with non-utility  generators  (NUGs),  the Company entered
into  contracts  for the supply of  substantial  capacity  from NUG  facilities.
Plants with approximately 2,100 MW of such capacity are in commercial operation,
and the related  charges are  reflected  in the  Company's  rates under the 1995
electric rate agreement.

As excess generating  capacity  developed in the Northeast,  estimates of future
market  prices for power  declined.  Since 1993 the  Company  has  entered  into
agreements  to  terminate  NUG  contracts  involving  725.6 MW at a cost of $212
million  (exclusive  of  interest),  $153  million  of which  has  already  been
recovered from customers. See "1995 Electric Rate Agreement" below.

The Company's  current  resource plans indicate that the Company's  service area
could  require  additional  generation  resources  within  the next five  years.
However,  the Company does not anticipate adding long-term capacity resources to
its electric system.  In a competitive  electric market,  unregulated  entities,
possibly including an unregulated affiliate of the Company, would be expected to
provide additional capacity resources as dictated by market conditions.

Competition and Industry Restructuring

In recent  years  federal  and New York  State  initiatives  have  promoted  the
development of competition in the sale of electricity  and gas. In general these
initiatives  "unbundle," or separate,  the integrated  services electric and gas
utilities  have  traditionally   provided,  and  enable  customers  to  purchase
electricity  and gas directly  from  suppliers  other than their local  utility.
Under these  initiatives  the Company  will  continue to  transport  and deliver
energy to customers in its service area,  including energy from other suppliers,
over its  electric  and gas systems.  The rates for such  delivery  services are
expected to remain regulated on a cost-of-service  basis.  These systems,  along
with  the  Company's  steam  system,  which  will  also  remain  rate-regulated,
comprised  more than 70 percent of the  Company's  net utility plant at December
31, 1996.

In a competitive electric marketplace, the Company could be disadvantaged by its
potential  "strandable"  costs.  Strandable  costs  are  prior  investments  and
commitments  that may not be  recoverable in a competitive  market.  The Company
estimates that, on a present value basis, its electric strandable costs could be
between $4.7  billion and $6.2  billion,  including  an  estimated  $650 million
relating to its fossil-fueled power plants, $1.1 billion relating to its nuclear
generating operations (including  decommissioning  costs) and $3 billion to $4.5
billion  relating to capacity  charges under the Company's  contracts with NUGs.
These estimates are forward-looking  statements.  Actual stranded costs might be
materially higher or lower than these estimates because of factors affecting the
future market price of capacity (such as competition  among capacity  providers,
changes  in  energy  usage  patterns  or  economic   conditions,   technological
developments,  or installation of new, or retirement of existing,  generation or
transmission  capacity),  changes in laws or  regulations,  and other  presently
unknown or unforeseen factors. See "PSC Settlement Agreement."

Competition  for  electric  sales in the  Company's  service  area could also be
affected by the limited  capacity of the existing  transmission  facilities  for
importing electricity.

In April 1996 the Federal Energy  Regulatory  Commission (FERC) issued its Order
888  requiring  electric  utilities  to  file   non-discriminatory  open  access
transmission  tariffs that would be available to wholesale sellers and buyers of
electric  energy and  allowing  utilities  to  recover  related  legitimate  and
verifiable  stranded  costs subject to FERC's  jurisdiction.  The Company's open
access tariff took effect in July 1996, subject to refund pending the outcome of
a hearing on the tariff  scheduled by FERC for August 1997. In December 1996 the
Company  filed a tariff to permit it to sell  electric  energy and  capacity  at
market-based  rates. In January 1997 the Company,  along with the other New York
electric  utilities,  submitted a filing to FERC for approval of a restructuring
of the wholesale electric market in New York State,  including the establishment
of an independent  system  operator that would control and operate most electric
transmission  facilities  in New  York as an  integrated  system,  and a  "power
exchange" that would establish visible spot market prices for wholesale energy.

In  May  1996  the  PSC  issued  an  order  in its  "Competitive  Opportunities"
proceeding  endorsing  a  fundamental  restructuring  of  the  electric  utility
industry in New York State,  based on  competition  in the generation and energy
services  sectors of the  industry. In March 1997 the Company and the PSC staff
entered  into a  Settlement  Agreement,  which is subject to PSC  approval.  The
Settlement   Agreement   reflects  the  Company's   strategy  for  dealing  with
competition,  including ongoing cost reductions, increased productivity, pursuit
of growth  opportunities  and  strengthening of customer  relations by providing
value-added  services.  The  extent to which the  Company  will  compete  in the
emerging  competitive  marketplace  will  depend  on the  outcome  of the  PSC's
Competitive  Opportunities  proceeding,   particularly  as  it  relates  to  the
corporate  reorganization  and  inter-affiliate  relationship  provisions of the
Settlement  Agreement,  and on management's  assessment  of the  potential for
increasing  shareholder  value through business  activities in this marketplace.
See "PSC Settlement Agreement."

All of the Company's gas customers,  either individually or by aggregating their
demand with other  customers,  became  eligible in 1996 to purchase gas directly
from suppliers other than the Company.


<PAGE>
                                       40



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. 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  year 1994,  the Company
accrued  incentives of $116.4 million,  before federal income tax, for attaining
certain  objectives  for the  Company's  Enlightened  Energy  program,  customer
service and fuel costs.

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  of
actual revenues in the prior rate year from those forecasts.  Implementation  of
the ERAM removed from Company  earnings the impact of all variations in electric
sales from forecasts,  including the effects of year-to-year weather variations,
changes in economic  conditions and the Enlightened Energy program.  In 1994 the
Company  set aside  $63.7  million  to be  returned  to  customers  for  revenue
overcollections under the ERAM.

1995 Electric Rate Agreement

In April 1995 the PSC approved a three-year  electric rate  agreement  effective
April 1, 1995. See, however, "PSC Settlement  Agreement." The principal features
of the 1995 electric rate agreement are as follows:

Limited  Changes  in Base  Revenues.  There  was no  increase  in base  electric
revenues for the first rate year of the  agreement  (the 12 months  ending March
31, 1996).  Differences between actual and projected amounts for certain expense
items for each rate year are subject to  reconciliation  and deferral for refund
to or recovery from customers in subsequent  years.  These items include pension
and  retiree  health  and life  insurance  expenses,  costs  incurred  under NUG
contracts,  and  certain  Enlightened  Energy  and  renewable  energy  expenses.
Likewise,  property tax differences are subject to reconciliation  and refund to
or recovery  from  customers,  except that the Company  absorbs (or  retains) 14
percent of any property tax increase (or decrease) from the forecast amounts.

Unlike previous  multi-year rate agreements,  there are 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.

In March  1996 the PSC  approved  rates  for the  second  year of the  agreement
effective April 1, 1996. Base electric rates were reduced by  approximately  $19
million (0.3 percent).  The decrease  reflects a lower allowed rate of return on
equity and a refund to customers  under the modified ERAM  mechanism,  offset in
part by increases in pension and retiree health expenses and NUG capacity costs.

In October  1996 the  Company  filed for an increase  to its  electric  rates to
become  effective  April 1, 1997,  for the third rate year of the electric  rate
agreement.   The  Company  currently   anticipates  no  change  in  the  revenue
requirement from the second rate year.

Return on Equity and Equity  Ratio.  The allowed rate of return on common equity
in the first  rate year was 11.1  percent.  The  allowed  return is  subject  to
adjustment  for the second  and third  rate years to reflect  changes in 30-year
Treasury  bond  rates.  The rate of return on equity for the second rate year is
10.31 percent.  For purposes of  calculating  the allowed  return,  a 52 percent
common equity ratio is assumed throughout the term of the agreement.

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

Earnings Sharing. Following each rate year the Company's actual return on equity
is calculated,  using actual  capitalization ratios and debt and preferred stock
costs,  but excluding  any earnings from the  incentives  discussed  below.  The
Company is permitted to retain 100 percent of any earnings up to 50 basis points
above the allowed rate of return for that rate year. The Company is permitted to
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 is required
to be deferred  for  customer  benefit.  The Company is  permitted  to retain 25
percent of  earnings  that  exceed the  allowed  rate of return by more than 150
basis  points;  one-third  of the  balance  above this level is  required  to be
deferred for customer benefit and two-thirds is required to be applied to reduce
rate base balances in a manner to be determined by the Company.

The rate of return on electric  common  equity,  excluding  incentives,  for the
first rate year exceeded the sharing threshold of 11.6 percent,  principally due
to increased productivity. As a result, the Company recorded a provision for the
future benefit of electric  customers of $10.2 million  (primarily in the fourth
quarter of 1995),  before federal income tax.  Similarly,  the Company estimates
the rate of return on electric  common  equity,  excluding  incentives,  for the
second  rate year will  exceed the  sharing  threshold  of 10.81  percent.  As a
result,  in 1996 the Company  recorded an  additional  provision  for the future
benefit of electric customers of $18.0 million, before federal income tax.

NUG  Termination  Costs.  The rate  agreement  provides for full recovery by the
Company of all NUG contract  termination costs incurred to date, and permits the
Company to petition  the PSC to defer for future  recovery  from  customers  the
costs of new NUG contract terminations or modifications, if any, during the term
of the agreement.


<PAGE>
                                       41




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 are also 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 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.

For 1996 the Company accrued benefits of $24.2 million and $6.1 million,  before
federal  income tax,  for the  Enlightened  Energy  incentive  and for  electric
customer service performance, respectively.

Partial  Pass-Through Fuel Adjustment Clause (PPFAC). A fuel and purchased power
cost-savings  incentive was continued with certain  modifications  from the 1992
electric rate agreement.  See Note A to the financial statements.  For each rate
year of the 1995 agreement,  there is 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 to achieve than
under the prior  agreement.  For 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.  For 1996 the Company earned
$24.9 million, before federal income tax, under the PPFAC.

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  that  result  from  changes in the number of
customers in each electric service classification. In effect the Company retains
additional  revenues  attributable  to added  customers,  but bears the  revenue
shortfall  resulting from lost  customers,  while other  variances from forecast
revenues are deferred for subsequent recovery from or refund to customers and do
not affect the Company's  earnings.  The ERAM and the RPC mechanism do not apply
to delivery service for the New York Power Authority (NYPA).

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 the total of such amounts 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 is
adjusted to reflect  such net  difference.  The RPC Factors are also  subject to
adjustment  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 Changes in Base Revenues."

For 1995 the Company set aside $35.3  million,  before federal income tax, to be
refunded to customers  for revenue  overcollections  under the ERAM and Modified
ERAM,  net of $13.3 million  earned under the RPC. For 1996 the Company  accrued
$10.1  million,  before  federal  income tax, to be recovered from customers for
revenue  undercollections  under the Modified  ERAM, net of $59.6 million earned
under the RPC.

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


PSC Settlement Agreement

On March 13, 1997, the Company and the PSC staff entered into a settlement
agreement (the Settlement Agreement) with respect to the PSC's Competitive
Opportunities proceeding. See "Competition and Industry Restructuring."

The  Settlement  Agreement,  which is subject to PSC  approval,  provides  for a
transition to a competitive  electric market by instituting "retail access" over
a  five-year  period  (the  Transition),  a rate  plan  for  the  Transition,  a
reasonable opportunity to recover prior utility investments and commitments that
may not be recoverable in a competitive  electric  market (often  referred to as
"strandable"  costs),  the  divestiture  by the  Company to  unaffiliated  third
parties  of at least 50 percent  of its New York City  fossil-fueled  generating
capacity,   and,  subject  to  shareholder  and  other  approvals,  a  corporate
reorganization into a holding company structure. A PSC order with respect to the
Settlement Agreement is expected by mid-1997.

The Company believes that the Settlement Agreement will not adversely affect its
eligibility to continue to apply Statement of Financial Accounting Standards No.
71,  "Accounting  for the  Effects  of  Certain  Types of  Regulation."  If such
eligibility were adversely affected, a material write-down of assets, the amount
of which is not presently determinable, could be required.


<PAGE>
                                       42




Retail Access.  The Company will implement an energy and capacity  retail access
program that will permit its customers to choose  alternative  energy suppliers.
The  delivery  of  electricity  to  customers  will  continue  to be through the
Company's  transmission and distribution systems. The program will begin in late
1997 with  certain  large  customers  and will be expanded to 500  megawatts  of
customer  load  within  12  months  following  PSC  approval  of the  Settlement
Agreement.  The  program  will be further  expanded  in annual  increments.  The
Company will target the phase-in of retail access to make it available to all of
its customers by the earlier of 24 months after the independent  system operator
becomes  fully  operational  or  December  2002.  This  schedule  is  subject to
adjustment as circumstances  warrant.  In general,  the Company's delivery rates
for retail access customers during the Transition will equal the rate applicable
to other comparable customers of the Company less the market value of the energy
and capacity being supplied for customers by the other sellers.

Rate  Plan.  The rate plan  reduces  the  generation-related  revenues  that the
Company  would have  received  over the  five-year  Transition  had current rate
levels  remained  in  effect by $655  million.  Base  rates  will be lower by 25
percent for the Company's largest industrial  customers and, by the last year of
the  Transition,  will be lower by 10 percent  for other  large  industrial  and
commercial  customers and 3.3 percent for  residential and other  customers.  In
general, base electric rates will not otherwise be changed during the Transition
except  in the  event  of  changes  in costs  above  anticipated  annual  levels
resulting  from legal or regulatory  requirements  (including a  requirement  or
interpretation  resulting in the Company's  refunding of its  tax-exempt  debt),
inflation  in  excess  of a 4  percent  annual  rate,  property  tax  increases,
environmental  costs  or in the  event  the  Company's  rate of  return  becomes
unreasonable for the provision of safe and adequate service.

The Settlement Agreement also provides, among other things, for a non-bypassable
system benefits charge to recover,  to the extent not otherwise  recovered,  the
costs of required  research  and  development,  energy  efficiency  programs and
programs  to assist low income  customers,  and a penalty  mechanism  (estimated
maximum,  $26 million per year) for failure to maintain  certain service quality
and reliability standards.

For any Transition  rate year, 50 percent of any earnings in excess of a rate of
return  of  12.9  percent  on  electric  common  equity  will  be  retained  for
shareholders and 50 percent will be applied for customer benefit,  with one-half
of such amount to be applied to a reduction of rates or as otherwise  determined
by the PSC and the  balance to be deferred  and applied to reduce the  Company's
generating plant balances through additional  depreciation  expense. The rate of
return calculation will exclude any incentives and reflect any amounts by which
the rate of return for earlier  Transition  rate years fell below 11.9  percent.
This  earnings  sharing  will end  beginning  in the year in which  the  Company
fulfills its divestiture  commitment (discussed below) or in which 15 percent of
the  service  area peak load  (excluding  the  existing  load served by NYPA) is
supplied other than by the Company.

The  Settlement  Agreement  supersedes  the provisions of the 1995 electric rate
agreement  prescribing  overall electric revenue levels for the 12 months ending
March 31, 1998. The Settlement  Agreement also  eliminates the provisions of the
1995  electric  rate  agreement  for  incentives  or  penalties  related  to the
Enlightened Energy program and customer service performance,  the modified ERAM,
earnings  sharing  and  reconciliation  of amounts  included  in base rates with
actual costs for pensions and other post-employment  benefits,  capacity charges
under  the  Company's  contracts  with  NUGs,  Enlightened  Energy  program  and
renewable energy expenses, property taxes and research and development expenses.
The Settlement  Agreement also requires the reversal of all related  balances at
March  31,1997,  the net  effect of which is not  expected  to be  material.  An
incentive-based fuel adjustment clause,  initially similar to the current PPFAC,
will be in effect during the Transition.

Divestiture  Commitment.  The Company has agreed to divest to unaffiliated third
parties  at  least 50  percent  of its New York  City  fossil-fueled  generating
capacity  no later  than  December  2002,  unless the PSC  determines  that such
divestiture  should be delayed or reduced  (to  maximize  sales price or address
other  developments).  Divestiture  could also be delayed  under  certain  other
circumstances.  The generating units not divested to unaffiliated  third parties
might be transferred to an unregulated affiliate of the Company. The Company has
agreed to submit a detailed  divestiture  plan to the PSC within one year of the
PSC's  approval  of  the  Settlement  Agreement.   The  PSC  could  approve  the
divestiture plan as submitted,  initiate a proceeding to address market power or
other concerns, or request the Company to respond to such concerns.

Recovery  of Prior  Investments  and  Commitments.  During the  Transition,  the
Company will continue to recover its potential  electric  strandable  costs (see
"Competition and Industry Restructuring") in the rates it charges all customers.
The  Company  will also  provide  during  the  Transition  for $350  million  of
additional  depreciation for its fossil-fueled  generating units and $45 million
for its Indian Point 2 nuclear unit. In addition,  as indicated  above,  certain
"excess" earnings will be applied as an offset to strandable costs.

Following the Transition,  the Company will be given a reasonable opportunity to
recover remaining  electric  strandable costs, as adjusted for any after-tax net
gain or loss  from  divestiture  or  transfer  of  generating  units,  through a
non-bypassable  charge to  customers.  For remaining  fossil-related  strandable
costs,  the recovery period will be 10 years and for the Company's  Indian Point
nuclear  station,  the recovery  period will be the  then-remaining  life of the
Indian  Point 2 unit.  With  respect to its NUG  contracts,  the Company will be
permitted to recover at least 90% of the amount by which the actual costs of its
purchases  under the  contracts  exceed market value after the  Transition.  Any
potential  disallowance after the Transition will be limited to the lower of (i)
10% of the  above-market  costs or (ii)  $300  million  (in 2002  dollars).  The
potential disallowance will be offset by NUG contract mitigation achieved by the
Company  after  the  beginning  of the  Transition  period  and 10% of the gross
proceeds  of  generating  unit  sales  to third  parties.  The  Company  will be
permitted a reasonable  opportunity to recover any costs subject to disallowance
that are not  offset by these two  factors  if it makes  good  faith  efforts in
implementing  provisions of the Settlement  Agreement leading to the development
of a competitive electric market in its service territory.

<PAGE>
                                       43




Any financing savings from  "securitization"  of the Company's  strandable costs
are  expected  to be  applied  to  further  reduce  customer  rates.  Subject to
satisfying any conditions of any securitization legislation enacted in New York,
the Company could  transfer its right to recover from  customers the payment for
the  strandable  costs to a financing  entity that would in return  remit to the
Company the proceeds of debt issued by the  financing  entity.  The debt,  which
would be non-recourse to the Company,  would be secured by, and repaid from, the
future customer payments.

Corporate Structure. The Settlement Agreement authorizes Con Edison to establish
a holding  company  and  establishes  guidelines  governing  transactions  among
affiliates.  The  formation  of the  holding  company is subject to  shareholder
approval, FERC approval and the consent of the Nuclear Regulatory Commission.

Upon formation of the holding  company,  the Company will become a subsidiary of
the holding company,  and the Company's common  shareholders will  automatically
become the  shareholders  of the holding  company.  The Company expects that the
holding  company would  initially also have  unregulated  energy supply,  energy
services and new ventures subsidiaries.  The energy supply subsidiary may become
an unregulated owner and operator of electric  generating plants and marketer of
electricity.   It  is  expected  that  the  Company's   existing  gas  marketing
subsidiary,  ProMark Energy, Inc., will be transferred to the holding company to
become a full-service provider of energy services engaging in both wholesale and
retail  sales  of  electricity  and  gas and  related  services.  Likewise,  the
Company's existing subsidiary, Gramercy Development, Inc., is expected to be the
"new ventures" subsidiary,  through which the holding company will develop other
opportunities  in both  energy and  non-energy  fields,  both  domestically  and
internationally.

The Settlement  Agreement limits the dividends that the Company could pay to the
holding  company to not more than 100 percent of income  available for dividends
calculated on a two-year rolling average basis.  Excluded from "income available
for dividends"  will be non-cash  charges to income  resulting  from  accounting
changes or charges to income  resulting from significant  unanticipated  events.
The limitation will not apply to dividends  necessary to transfer to the holding
company proceeds from major  transactions,  such as asset sales, or to dividends
reducing the  Company's  capital ratio to a level  appropriate  to the Company's
business risk.

Litigation.   Pursuant to the Settlement Agreement, the Company will terminate
an appeal of a November 1996 rejection by the Supreme Court of the State of
New York of a challenge to the PSC's May 1996 order.

Gas and Steam Rate Agreements

In September  1993 the PSC granted the Company  permission  to increase its firm
gas rates for the second rate year of a 1992 gas rate agreement by $21.6 million
(2.8  percent).  In lieu of an increase of $2.1 million for the second rate year
of a 1992 steam rate agreement, the PSC authorized the Company to retain certain
tax refunds being held by the Company for refund to steam customers.

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 12 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.  The gas  agreement  contained two incentive
mechanisms  providing  for rewards or  penalties.  In 1995 the  Company  accrued
benefits of $6.1  million  and $1.3  million,  before  federal  income tax,  for
performance  under the gas system  improvement and customer service  incentives,
respectively.  In 1996 the Company  accrued  benefits  of $6.5  million and $2.7
million,  before federal income tax, for the gas system improvement and customer
service incentives, respectively.

Effective  October 1, 1995 (the beginning of the second year of the 1994 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.

In September  1996 the PSC  approved  rates for the third year of the 1994 steam
rate  agreement.  Effective  October 1, 1996, base steam rates were increased by
$12.1 million (3.44  percent).  The  calculated  increase for the third year was
$22.9 million (6.52  percent).  However,  under the provisions of the agreement,
the increase was capped,  and the balance of $10.8  million will be eligible for
recovery in a future period.

In  November  1996 the Company  filed a request for a four-year  steam rate plan
that would  provide  annual rate  increases of $16.6 million (4.6 percent in the
first rate year). The plan levelizes what would otherwise be a request for a $44
million  increase  (12.1  percent in the first rate  year),  followed by smaller
increases in subsequent  years.  The first increase  would be effective  October
1997 and the four-year  plan would end in September  2001. The major reasons for
the  increase  are the  recovery of the $10.8  million  from the 1994 steam rate
agreement;  proposed increases in depreciation  rates;  increases in steam plant
operation and maintenance  expenses;  the effect of transferring  certain common
facilities to steam operations; and an increase in the allowed rate of return on
equity from 10.9 percent to 11.6 percent.

In January 1997 the PSC approved a four-year gas rate settlement agreement under
which the Company withdrew its request for an increase to base gas rates for the
third rate year of the 1994 gas rate  agreement  (which was to have taken effect
on October 1, 1996). The new agreement  contains the following major provisions:
base rates will,  with limited  exceptions,  remain at September 30, 1996 levels
through  September  30,  2000;  the  Company  will  share  in net  revenue  from
interruptible gas sales (previously used only to reduce firm customer gas costs)
by retaining  in each rate year the first $7.0 million of net revenue  above 8.5
million dekatherms and 50 percent of additional net revenues;  and 86 percent of
any increase in property taxes above levels  implicit in rates will be recovered
by offsetting  amounts,  if any, that would  otherwise be returned to customers.
The  incentive  mechanisms  under the 1994 gas  agreement  will be  discontinued
effective  October  1997,  after which the Company  will be subject to a penalty
(maximum,  $1.7  million  per year) if it fails to maintain  targeted  levels of
customer  satisfaction;  and the Company will share with customers 50 percent of
earnings above a 13 percent rate of return on gas common equity.


<PAGE>
                                       44




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.  New  York and ten  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 compliance  with these phases could require capital  expenditures
of approximately $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 a permanent  operating  repository  before 2015. In July 1996 the
United  States Court of Appeals for the  District of Columbia  held that the DOE
has an obligation "reciprocal to the utilities' obligation to pay fees, to start
disposing  of the [spent  nuclear  fuel] no later  than  January  31,  1998." In
January 1997 the Company and a number of other  utilities  petitioned the United
States Court of Appeals for the District of Columbia for an order directing the
DOE to  implement  a program  enabling it to begin  acceptance  of spent fuel by
1998, and to provide relief from any obligation to pay further fees to DOE until
waste disposal  commences,  authorization  to pay (under certain  circumstances)
into an escrow account fees which would  otherwise be payable to DOE pursuant to
the spent nuclear fuel disposal  contracts  and enhanced  judicial  oversight of
DOE's performance under the contracts.

The Company  estimates  that it 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 Agreement

In June 1996 the Company  concluded a new collective  bargaining  agreement with
the union representing  approximately two-thirds of the Company's employees. The
four-year  agreement  provides for general wage increases of 2.5 percent in each
of the first two years and 3.0 percent in each of years  three and four,  with a
potential 0.5 percent additional merit-based increase in each year.

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>
                                       45


RESULTS OF OPERATIONS


Earnings per share were $2.93 in 1996 and 1995 and $2.98 in 1994.  The  average
number of common shares  outstanding  for 1996, 1995 and 1994 was 235.0 million,
234.9 million and 234.8 million, respectively.

Earnings for 1996, 1995 and 1994 reflect electric,  gas and steam rate increases
or  decreases,  and  other  provisions  of the  electric,  gas  and  steam  rate
agreements discussed above.

Operating Revenues and Fuel Costs

Operating  revenues  in 1996 and 1995  increased  from the prior  year by $422.8
million  and by  $163.8  million,  respectively.  The  principal  increases  and
decreases in revenue were:

                                                  Increase (Decrease)
                                                   1996            1995
(Millions of Dollars)                         over 1995       over 1994

Electric, gas and steam rate changes .....       $   .8          $ 29.3
Fuel rider billings* .....................        319.7            22.4
Sales volume changes
    Electric** ...........................          2.9            41.4
     Gas .................................        124.2           (11.7)
    Steam ................................          8.1           (13.9)
Gas weather normalization ................        (18.5)            5.9
Electric:
    ERAM/Modified ERAM accruals ..........         45.4            28.4
    Recoveries (refunds) of prior
    rate year ERAM accruals ..............        (25.9)           83.1
    Rate refund provision ................         (8.2)          (10.0)
    Off-system sales .....................         (4.8)           12.5
Other ....................................        (20.9)          (23.6)
Total ....................................       $422.8        $  163.8
* 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.

The increase in fuel  billings in 1996  reflects  increases in the unit costs of
both  purchased  power and fuel  used to  produce  electricity  and steam and an
increase  in the unit cost of gas  purchased  for resale.  The  increase in fuel
billings in 1995 reflects higher unit costs of electric purchased power,  offset
by a lower unit cost of gas.  Electric  fuel costs  increased  $23.3  million in
1996,  largely  because of the Company's  increased  unit cost of fuel partially
offset by lower generation.  Electric  purchased power costs increased by $161.9
million over the 1995 period  reflecting  a higher unit cost of power  purchased
under NUG contracts. The increases in electric fuel and purchased power costs in
1996  were  mitigated  by the  greater  availability  in  1996  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.
Gas purchased for resale  increased  $158.5 million in 1996,  reflecting  higher
unit costs of purchased  gas and higher  sendout.  The unit cost of gas was 48.8
percent  higher in 1996 than in 1995 and was 20.2 percent  lower in 1995 than in
1994.  Steam fuel and purchased  steam costs increased $49.7 million in 1996 due
to the higher unit cost of fuel.

Electricity  sales  volume in the  Company's  service  territory  increased  0.8
percent in 1996 and 0.7  percent  in 1995.  Gas sales  volume to firm  customers
increased 8.9 percent in 1996 and decreased 2.8 percent in 1995.  Transportation
of customer-owned  gas decreased 67.1 percent in 1996 and increased 65.3 percent
in 1995, primarily due to variations in the volume of gas transported for use by
NYPA as boiler  fuel at its  Poletti  unit.  Steam sales  volume  increased  1.9
percent in 1996 and decreased 4.1 percent in 1995.

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 0.9 percent in 1996 and
1.2 percent in 1995.  Similarly  adjusted,  gas sales  volume to firm  customers
increased  1.9 percent in 1996 and 0.1 percent in 1995,  and steam sales  volume
decreased  0.1 percent in 1996 and 1.9 percent in 1995.  Weather-adjusted  sales
represent  the  Company's  estimate  of the sales  that  would have been made if
historical average weather conditions had prevailed.



<PAGE>
                                       46


Off-system  electricity sales were 3,917 millions of kilowatthours (kWh) in 1996
compared  with  5,035  millions  of  kWh  in  1995.   Off-system  sales  include
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 decreased 1.8 percent in 1996 and were
unchanged in 1995.  For 1996 the decrease  reflects lower  production  expenses,
principally  due to the refueling and  maintenance  outage of the Indian Point 2
nuclear unit in 1995;  there was no such outage in 1996. The decrease was offset
in part by higher pension and retiree  benefit costs due to changes in actuarial
assumptions.  For 1995 lower  administrative and general expenses and production
expenses  at  fossil-fueled  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 that year.

In 1996 the Company accrued $10 million for environmental liabilities related to
various  Superfund  sites.  During  1995 the  Company  accrued  $10  million for
environmental  remediation  costs relating to Company  facilities  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.  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.

Taxes, Other Than Federal Income Tax

At $1.2  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:

                                                         Increase (Decrease)
                                      1996               1996            1995
(Millions of Dollars)                Amount         over 1995       over 1994

Property taxes ..................   $ 571.6             $37.6           $(5.4)
State and local taxes on revenues .   473.9              13.6            (2.2)
Payroll taxes .....................    60.8               2.6              .4
Other taxes .......................    59.9              (7.8)            (.3)
Total                              $1,166.2*            $46.0           $(7.5)
* Including  sales  taxes on  customers'  bills, total taxes, other than 
  federal income taxes, billed to customers in 1996 were $1,478.9 million.

The increase in property taxes in 1996 reflects higher assessed valuations.  The
reduction  in property  taxes in 1995  reflects a decrease in the share of total
New York City  property  taxes borne by the  Company.

Other Income

Other income  decreased $7.5 million in 1996 and increased $8.2 million in 1995.
The variations in other income reflect  primarily  changes in interest rates and
the level of temporary cash investment balances.

Net Interest  Charges and  Preferred  Stock  Dividend  Requirements

Interest on long-term  debt  increased $5.9 million in 1996 and $12.9 million in
1995 principally as a result of new debt issues. The increase in 1996 relates to
the preferred stock refunding discussed above, which  substantially  reduced the
Company's preferred stock dividend requirements.  Other interest decreased $11.6
million  in 1996,  principally  as a result of lower  interest  associated  with
certain tax settlements and customer overpayments. Other interest increased $9.1
million in 1995, principally as a result of a higher rate of interest applied to
customer deposits and interest associated with certain tax settlements.

Federal Income Tax

Federal income tax decreased $1.4 million in 1996 and $41.0 million in 1995
reflecting the changes each year in income before tax and in tax credits. See
Note I to the financial statements.

March 13, 1997

<PAGE>
                                       47






ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


A. Financial Statements

                                                                  Page
      Index to Financial Statements                               Number

      Report of Independent Accountants                           49

      Consolidated Balance Sheet at December 31, 1996
         and 1995                                                 50-51

      Consolidated Income Statement for the years ended
         December 31, 1996, 1995 and 1994                         52

      Consolidated Statement of Cash Flows for the years
         ended December 31, 1996, 1995 and 1994                   53

      Consolidated Statement of Capitalization at
         December 31, 1996 and 1995                               54-55

      Consolidated Statement of Retained Earnings for the
         years ended December 31, 1996, 1995 and 1994             56

      Notes to Consolidated Financial Statements                  56-64

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

      Schedule VIII - Valuation and Qualifying Accounts           65-67



      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>
                                       48






B. Supplementary Financial Information

      Selected Quarterly Financial Data for the years ended December 31, 1996
      and 1995 (Unaudited)

                              First       Second      Third       Fourth
1996 (Millions of Dollars)    Quarter     Quarter     Quarter     Quarter

Operating revenues ......... $1,867.4    $1,539.7    $1,920.3    $1,632.3
Operating income ...........    252.7       152.3       409.4       199.2
Net income .................    174.5        71.4       328.0       120.2
Net income for common stock     182.5        66.8       323.4       115.5
Earnings per common share ..     $.78        $.28       $1.38        $.49


                              First       Second      Third       Fourth
1995 (Millions of Dollars)   Quarter     Quarter     Quarter      Quarter

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


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

<PAGE>
                                       49





                      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 47 present  fairly,  in all material  respects,  the
financial  position of  Consolidated  Edison  Company of New York,  Inc. and its
subsidiaries at December 31, 1996 and 1995, and the results of their  operations
and their cash flows for each of the three  years in the period  ended  December
31, 1996 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

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

March 13, 1997


<PAGE>
                                       50




<TABLE>

Consolidated Balance Sheet
Consolidated Edison Company of New York, Inc.

Assets
At December 31 (Thousands of Dollars)                             1996                       1995
<S>                                                        <C>                       <C>

Utility plant, at original cost (Notes A and B)
Electric                                                   $11,588,344                $11,319,622
Gas                                                          1,642,231                  1,537,296
Steam                                                          536,672                    462,975
General                                                      1,152,001                  1,085,795
Total                                                       14,919,248                 14,405,688
Less: Accumulated depreciation                               4,285,732                  4,036,954
Net                                                         10,633,516                 10,368,734
Construction work in progress                                  332,333                    360,457
Nuclear fuel assemblies and components,
  less accumulated amortization                                101,461                     85,212
Net utility plant                                           11,067,310                 10,814,403

Current assets
Cash and temporary cash investments (Note A)                   106,882                    342,292
Accounts receivable - customers,
  less allowance for uncollectible accounts
   of $21,600 in 1996 and 1995                                 544,004                    497,215
Other receivables                                               42,056                     45,558
Regulatory accounts receivable (Note A)                         45,397                     (6,481)
Fuel, at average cost                                           64,709                     40,506
Gas in storage, at average cost                                 44,979                     26,452
Materials and supplies, at average cost                        204,801                    221,026
Prepayments                                                     64,492                     66,148
Other current assets                                            15,167                     15,126
Total current assets                                         1,132,487                  1,247,842

Investments and nonutility property
                                                               177,224                    145,646
Deferred charges (Note A)
Enlightened Energy program costs                               133,718                    144,282
Unamortized debt expense                                       130,786                    133,812
Recoverable fuel costs (Note A)                                101,462                     59,454
Power contract termination costs                                58,560                    105,408
Other deferred charges                                         271,356                    256,783
Total deferred charges                                         695,882                    699,739

Regulatory asset - future federal
  income taxes (Notes A and I)                                 984,282                  1,042,260

Total                                                      $14,057,185                $13,949,890


</TABLE>


<PAGE>
                                       51


<TABLE>

Capitalization and Liabilities
At December 31 (Thousands of Dollars)                             1996                   1995
<S>                                                        <C>                   <C>    
Capitalization (see Consolidated Statement       
                of Capitalization)
Common shareholders' equity                                $ 5,727,568            $ 5,522,734
Preferred stock subject to mandatory
  redemption (Note B)                                           84,550                100,000
Other preferred stock (Note B)                                 238,098                539,917
Long-term debt                                               4,238,622              3,917,244
Total capitalization                                        10,288,838             10,079,895


Noncurrent liabilities
Obligations under capital leases                                42,661                 45,250
Other noncurrent liabilities                                    80,499                 75,907
Total noncurrent liabilities                                   123,160                121,157


Current liabilities
Long-term debt due within one year
  (Note B)                                                     106,256                183,524
Accounts payable                                               431,115                420,852
Customer deposits                                              159,616                158,366
Accrued taxes                                                   27,342                 24,374
Accrued interest                                                83,090                 89,374
Accrued wages                                                   80,225                 76,459
Other current liabilities                                      147,968                168,477
Total current liabilities                                    1,035,612              1,121,426


Provisions related to future federal
  income taxes and other deferred
   credits (Notes A and I)
Accumulated deferred federal income tax                      2,289,092              2,296,284
Accumulated deferred investment tax credits                    172,510                181,420
Other deferred credits                                         147,973                149,708
Total deferred credits                                       2,609,575              2,627,412

Contingencies (Note F)

Total                                                      $14,057,185            $13,949,890

The accompanying notes are an integral part of these financial statements.

</TABLE>


<PAGE>
                                       52

<TABLE>

Consolidated Income Statement
Consolidated Edison Company of New York, Inc.

Year Ended December 31 (Thousands of Dollars)     1996                1995                 1994
<S>                                         <C>                 <C>                  <C>   
Operating revenues (Note A)
Electric                                    $5,541,117          $5,389,408           $5,140,472
Gas                                          1,015,070             813,356              890,107
Steam                                          403,549             334,133              342,507
Total operating revenues                     6,959,736           6,536,897            6,373,086

Operating expenses
Purchased power                              1,272,854           1,107,223              787,455
Fuel                                           573,275             504,104              567,764
Gas purchased for resale                       418,271             259,789              341,204
Other operations                             1,163,337           1,139,732            1,146,094
Maintenance                                    458,637             512,102              506,179
Depreciation and amortization (Note A)         496,412             455,776              422,356
Taxes, other than federal income tax         1,166,199           1,120,232            1,127,691
Federal income tax (Notes A and I)             397,160             396,560              438,160
Total operating expenses                     5,946,145           5,495,518            5,336,903

Operating income                             1,013,591           1,041,379            1,036,183

Other income (deductions)
Investment income (Note A)                       8,327              16,966               10,601
Allowance for equity funds used
    during construction (Note A)                 3,468               3,763                8,354
Other income less miscellaneous deductions      (8,749)             (8,149)             (15,201)
Federal income tax (Notes A and I)                 970              (1,060)                (430)
Total other income                               4,016              11,520                3,324

Income before interest charges               1,017,607           1,052,899            1,039,507
Interest on long-term debt                     307,820             301,917              289,060
Other interest                                  17,331              28,954               19,853
Allowance for borrowed funds used
    during construction (Note A)                (1,629)             (1,822)              (3,676)
Net interest charges                           323,522             329,049              305,237

Net income                                     694,085             723,850              734,270

Preferred stock dividend requirements          (19,859)            (35,565)             (35,587)
Gain on refunding of preferred stock
 (Note B)                                       13,943                  --                   --
Net income for common stock                 $  688,169         $   688,285          $   698,683
Earnings per common share based on
  average number of shares outstanding
  during each year (234,976,697;
  234,930,301 and 234,753,901)              $    2.93          $      2.93          $      2.98

The accompanying notes are an integral part of these financial statements.

</TABLE>

<PAGE>
                                       53

<TABLE>


Consolidated Statement of Cash Flows
Consolidated Edison Company of New York, Inc.

Year Ended December 31 (Thousands of Dollars)               1996              1995              1994
<S>                                                   <C>               <C>                <C>   
Operating activities
Net income                                            $  694,085        $  723,850         $  734,270
Principal non-cash charges (credits)
  to income
Depreciation and amortization                            496,412           455,776            422,356
Deferred recoverable fuel costs                          (42,008)          (61,937)            20,132
Federal income tax deferred                               40,600            69,020             64,090
Common equity component of allowance
  for funds used during construction                      (3,274)           (3,546)            (7,876)
Other non-cash charges                                     9,602            14,382             45,537

Changes in assets and liabilities
Accounts receivable - customers,
    less allowance for uncollectibles                    (46,789)          (56,719)            18,765
Regulatory accounts receivable                           (51,878)           32,827             70,771
Materials and supplies, including
  fuel and gas in storage                                (26,505)           43,341             17,306
Prepayments, other receivables
  and other current assets                                 5,117             4,566             21,317
Enlightened Energy program costs                          10,564            25,919            (30,144)
Power contract termination costs                          30,827            55,387            (62,376)
Accounts payable                                          10,263            46,383            (18,074)
Other - net                                              (19,679)          (72,785)           (46,161)
Net cash flows from operating activities                1,107,337        1,276,464          1,249,913

Investing activities including construction
Construction expenditures                               (675,233)         (692,803)          (757,530)
Nuclear fuel expenditures                                (48,705)          (12,840)           (47,071)
Contributions to nuclear decommissioning trust           (21,301)          (18,893)           (14,586)
Common equity component of allowance for funds
    used during construction                               3,274             3,546              7,876
Net cash flows from investing activities
    including construction                              (741,965)         (720,990)          (811,311)

Financing activities including dividends
Issuance of common stock                                    --                --               14,650
Issuance of long-term debt                               525,000           228,285            400,000
Retirement of long-term debt                            (183,524)          (10,889)          (133,639)
Advance refunding of preferred stock                    (316,982)             --                 -- 
Advance refunding of long-term debt                      (95,329)         (155,699)              --
Issuance and refunding costs                             (18,480)           (5,269)            (5,988)
Common stock dividends                                  (488,756)         (479,262)          (469,561)
Preferred stock dividends                                (22,711)          (35,569)           (35,599)
Net cash flows from financing activities
    including dividends                                 (600,782)         (458,403)          (230,137)

Net increase (decrease) in cash and
    temporary cash investments                          (235,410)           97,071            208,465
Cash and temporary cash investments at January 1         342,292           245,221             36,756
Cash and temporary cash
    investments at December 31                        $  106,882        $  342,292         $  245,221

Supplemental disclosure of cash flow information
  Cash paid during the period for:
    Interest                                          $  309,279        $  309,953         $  269,839
    Income taxes                                         346,755           344,754            385,355


The accompanying notes are an integral part of these financial statements.

</TABLE>


<PAGE>
                                       54

<TABLE>


Consolidated Statement of Capitalization
Consolidated Edison Company of New York, Inc.


At December 31 (Thousands of Dollars)                                                                     1996              1995
                                                              Shares outstanding
                                                      December 31, 1996      December 31, 1995
<S>                                                         <C>                    <C>               <C>               <C>     

Common shareholders' equity (Note B)
Common stock, $2.50 par value,
    authorized 340,000,000 shares                           234,993,596            234,956,299       $1,478,536        $1,464,305
Retained earnings                                                                                     4,283,935         4,097,035
Capital stock expense                                                                                   (34,903)          (38,606)
Total common shareholders' equity                                                                     5,727,568         5,522,734
Preferred stock (Note B)
Subject to mandatory redemption
Cumulative Preferred, $100 par value,
    7.20% Series I                                              475,000                500,000           47,500            50,000
    6 1/8% Series J                                             370,500                500,000           37,050            50,000
Total subject to mandatory redemption                                                                    84,550           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                                         70,612                600,000            7,061            60,000
    5 1/4%      Series B                                        138,438                750,000           13,844            75,000
    4.65%       Series C                                        153,296                600,000           15,330            60,000
    4.65%       Series D                                        222,330                750,000           22,233            75,000
    5 3/4%      Series E                                             --                500,000               --            50,000
    6.20%       Series F                                             --                400,000               --            40,000
Cumulative Preference, $100 par value,
     authorized 2,250,000 shares
    6% Convertible Series B                                      46,305                 49,174            4,630             4,917
Total other preferred stock                                                                             238,098           539,917
Total preferred stock                                                                                $  322,648        $  639,917
* Represents total authorized  shares of cumulative  preferred stock, $100 par
 value, including preferred stock subject to mandatory redemption.

</TABLE>

<PAGE>
                                       55

<TABLE>



At December 31 (Thousands of Dollars)                   1996               1995
Long-term debt (Note B)
Maturity       Interest Rate       Series
<S>               <C>            <C>                 <C>             <C>
First and Refunding Mortgage Bonds (open-end mortgage):
1996              5   %             CC               $        --     $   100,000
1996              5.90              DD                        --          75,000
Total mortgage bonds                                          --         175,000

Debentures:
1997              5.30 %         1993E                   100,000         100,000
1998              6 1/4          1993A                   100,000         100,000
1998              5.70           1993F                   100,000         100,000
1999              6 1/2          1992D                    75,000          75,000
1999                *            1994B                   150,000         150,000
2000              7 3/8          1992A                   150,000         150,000
2000              7.60           1992C                   125,000         125,000
2001              6 1/2          1993B                   150,000         150,000
2001                *            1996B                   150,000              --
2002              6 5/8          1993C                   150,000         150,000
2003              6 3/8          1993D                   150,000         150,000
2004              7 5/8          1992B                   150,000         150,000
2005              7 3/8          1992E                    75,000          75,000
2005              6 5/8          1995A                   100,000         100,000
2023              7 1/2          1993G                   380,000         380,000
2026              9 3/8          1991A                        --          95,329
2026              7 3/4          1996A                   100,000              --
2027              8.05           1992F                   100,000         100,000
2029              7 1/8          1994A                   150,000         150,000
Total debentures                                       2,455,000       2,300,329

Tax-exempt debt - notes issued to New York State Energy Research
                   and Development Authority for Facilities Revenue Bonds:
2020              6.10 %         1995A                   128,285         128,285
2020              5 1/4          1993B                   127,715         127,715
2021              7 1/2          1986A                   150,000         150,000
2022              7 1/8          1987A                   100,855         100,855
2022              9 1/4          1987B                    29,385          29,385
2022              5 3/8          1993C                    19,760          19,760
2024              7 3/4          1989A                   150,000         150,000
2024              7 3/8          1989B                   100,000         100,000
2024              7 1/4          1989C                   150,000         150,000
2025              7 1/2          1990A                   150,000         150,000
2026              7 1/2          1991A                   128,150         128,150
2027              6 3/4          1992A                   100,000         100,000
2027              6 3/8          1992B                   100,000         100,000
2028              6              1993A                   101,000         101,000
2029              7 1/8          1994A                   100,000         100,000
Total tax-exempt debt                                  1,635,150       1,635,150

Subordinated deferrable interest debentures:
2031              7 3/4%         1996A                   275,000              --

Other long-term debt                                       8,848          19,163
Unamortized debt discount                               (29,120)        (28,874)

Total                                                  4,344,878       4,100,768

Less: Long-term debt due within one year                 106,256         183,524

Total long-term debt                                   4,238,622       3,917,244

Total capitalization                                 $10,288,838     $10,079,895

*Rate reset quarterly. At December 31, 1996 the rates for the Series 1994 B
 and the Series 1996 B were 5.8125% and 5.65078%, respectively.
 
 The accompanying notes are an integral part of these financial statements.

</TABLE>


<PAGE>
                                       56

<TABLE>

Consolidated Statement of Retained Earnings
Consolidated Edison Company of New York, Inc.


Year Ended December 31 (Thousands of Dollars)         1996              1995              1994
<S>                                            <C>                <C>               <C>   
Balance, January 1                              $4,097,035        $3,888,010        $3,658,886
Net income for the year                            694,085           723,850           734,270
Total                                            4,791,120         4,611,860         4,393,156
Dividends declared on capital stock
Cumulative Preferred, at required annual rates      18,145            35,259            35,259
Cumulative Preference, 6% Convertible Series B         284               304               326
Common, $2.08, $2.04 and $2.00 per share           488,756           479,262           469,561
Total dividends declared                           507,185           514,825           505,146
Balance,  December 31                           $4,283,935         $4,097,035       $3,888,010 

The accompanying notes are an integral part of these financial statements.
</TABLE>


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.

Statement of Financial  Accounting Standards (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,  "Accounting  for the Effects of Certain Types of  Regulation,"  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  application  of SFAS  No.  121 had no  effect  on the  Company's
financial position or results of operations in 1996.

On March 13, 1997, the Company entered into a Settlement  Agreement with the PSC
staff with  respect to the PSC's  "Competitive  Opportunities"  proceeding.  The
Settlement  Agreement,  which  is  subject  to  PSC  approval,  provides  for  a
transition  to a  competitive  electricity  market over a five-year  period (the
Transition), a rate plan for the Transition, a reasonable opportunity to recover
prior utility  investments  and  commitments  that may not be  recoverable  in a
competitive  electric  market (often  referred to as  "strandable"  costs),  the
divestiture by the Company to unaffiliated  third parties of at least 50 percent
of its  New  York  City  fossil-fueled  generating  capacity,  and,  subject  to
shareholder  and other  approvals,  a  corporate  reorganization  into a holding
company  structure.  The Settlement  Agreement  will change  certain  accounting
policies  described in these notes.  The Company  believes  that the  Settlement
Agreement  will not adversely  affect its  eligibility to continue to apply SFAS
No. 71. If such eligibility were adversely  affected,  a material  write-down of
assets, the amount of which is not presently determinable, could be required.

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.

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 9.0
percent  in 1996,  9.1  percent in 1995 and 9.4  percent  in 1994.  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  3.4 percent in 1996, 3.3 percent in
1995 and 3.2 percent in 1994. In 1996 an additional

<PAGE>
                                       57



provision for  depreciation  of $13.9  million was accrued in connection  with a
preferred stock refunding. See Note B.

The  Company is a joint owner of two  1,200-megawatt  (MW)  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, 1996 and
1995 was:

(Thousands of Dollars)                              1996                 1995
Bowline Point: Plant in service                 $204,484             $203,360
  Construction work in progress                    2,788                2,340
Roseton: Plant in service                        146,623              145,207
  Construction work in progress                      846                2,089

The  Company's  share of  accumulated  depreciation  for the Roseton  station at
December 31, 1996 and 1995 was $70.3 million and $64.8 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.

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  accumulated  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 Nuclear  Regulatory  Commission  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, 1996 and 1995,  which
include earnings on funds externally invested, were as follows:

                              Amounts Included in
                         Accumulated Depreciation
(Millions of Dollars)         1996           1995
Nuclear                    $ 164.7        $ 134.4
Non-Nuclear                   57.0           55.3
Total                      $ 221.7        $ 189.7

For the 12 months ended March 31, 1995, the Company provided 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 a 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 a 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.

The  Financial  Accounting  Standards  Board (FASB) is currently  reviewing  the
utility  industry's  accounting  treatment  of nuclear and  certain  other plant
decommissioning   costs.  In  the  exposure   draft,   "Accounting  for  Certain
Liabilities  Related to Closure or  Removal  of  Long-Lived  Assets,"  issued in
February 1996, the FASB 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.  Discussions  of  issues
addressed in the exposure draft are ongoing.

Nuclear Fuel. Nuclear fuel assemblies  and components are amortized to operating
expenses   based  on  the  quantity  of  heat  produced  in  the  generation  of
electricity.  Fuel  costs  also  include  provisions  for  payments  to the U.S.
Department of Energy (DOE) for future off-site storage of the spent fuel and for
a portion of the costs to decontaminate and decommission the DOE facilities used
to enrich  uranium  purchased by the  Company.  Such  payments  amounted to $9.8
million in 1996. Nuclear fuel costs are recovered in revenues through base rates
or through the fuel adjustment clause.

Leases.  In accordance with SFAS No. 71, 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,  gas and steam  service are  recognized  on a
monthly  billing  cycle  basis.  Pursuant  to the 1992 and  1995  electric  rate
agreements,  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 an electric revenue
adjustment  mechanism  (ERAM).  The 1995  agreement  introduced  a  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  rewards (or penalties)  earned under incentive
mechanisms for the Enlightened Energy  (demand-side  management) 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 1994 and 1997 gas rate  agreements  provide for revenues to be increased (or
decreased) each month to reflect  rewards (or penalties)  earned under incentive
mechanisms related to gas customer service and system improvement targets.


<PAGE>
                                       58


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  electric 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.

Regulatory  Accounts Receivable.  Regulatory accounts receivable at December 31,
1996 amounted to $45.4 million, reflecting accruals under the 1995 electric rate
agreement and the 1994 gas rate agreement for incentive  benefits related to the
Company's  Enlightened  Energy program ($29.1  million),  and electric  customer
service activities ($5.5 million),  for the amounts to be billed under the PPFAC
($3.5 million),  for incentive  benefits related to gas system improvement ($4.9
million)  and gas customer  service  ($2.0  million) and for net electric  sales
revenues in  accordance  with the  Modified  ERAM ($0.4  million).  The revenues
accrued in a given  12-month  period under the 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 12-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  program for future  recovery from
ratepayers.  Such deferrals  amounted to $133.7 million at December 31, 1996 and
$144.3  million at  December  31,  1995.  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,  1996 and 1995 the  trust  fund
amounted to $164.7 million and $134.4  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.

Gas  Hedging.  In 1996 the  Company  initiated  a  program  to hedge the cost of
natural gas in storage  against adverse market price  fluctuations.  The Company
defers  hedging gains and losses until the underlying gas commodity is withdrawn
from  storage  and  then  adjusts  the cost of its gas in  storage  accordingly.
Hedging  losses or gains are  charged  or  credited  to  customers  through  the
Company's gas fuel adjustment clause.  Hedging losses deferred on open positions
at December 31, 1996 were not material.

Federal  Income Tax. In  accordance with SFAS No. 109,  "Accounting  for Income
Taxes," the Company has  recorded an  accumulated  deferred  federal  income tax
liability for substantially all temporary  differences  between the book and tax
bases of assets and  liabilities at current tax rates.  In accordance  with rate
agreements,  the Company has recovered  amounts from  customers for a portion of
the tax expense the Company  will pay in the future as a result of the  reversal
or "turn-around" of these temporary  differences.  As to the remaining temporary
differences,  in  accordance  with SFAS No. 71, the  Company has  established  a
regulatory asset for the net revenue requirements to be recovered from customers
for the related  future tax  expense.  In 1993 the PSC issued an Interim  Policy
Statement  proposing  accounting  procedures  consistent  with SFAS No.  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. See Note I.

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.

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 1996, 1995
and  1994,  amounting  to  $32.3  million,  $45.0  million  and  $46.8  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.

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 1996, 1995 and 1994, 2,869 shares,
3,928 shares and 4,176 shares of Series B preference  stock were  converted into
37,297 shares, 51,064 shares and 54,288 shares of common stock, respectively. At
December 31, 1996,  601,965  shares of unissued  common stock were  reserved for
conversion of preference stock.

<PAGE>
                                       59




The prices at which the  Company  has the option to redeem its  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
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  $104.32  per  share,  plus  accrued
dividends, if redeemed prior to May 1, 1997 (and thereafter at prices declining
annually to $100 per share,  plus  accrued  dividends,  after  April 30,  2002).
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.

Preferred Stock Refunding. In March 1996 the Company canceled approximately $227
million of its preferred stock purchased pursuant to a tender offer and redeemed
an additional  $90 million of its preferred  stock.  In accordance  with the PSC
order approving the issuance of subordinated  deferrable  interest debentures to
refund the preferred  stock, the Company offset the net gain of $13.9 million by
accruing an additional provision for depreciation equal to the net gain.

Dividends. No  dividends  may be paid,  or funds set apart for  payment,  on the
Company's  Cumulative  Preference  Stock or common  stock  until  all  dividends
accrued on the $5 Cumulative Preferred Stock and Cumulative Preferred Stock have
been paid, or declared and set apart for payment,  and unless the Company is not
in arrears on its mandatory redemption  obligation for the Series I and Series J
Cumulative  Preferred  Stock.  No dividends  may be paid on any of the Company's
capital  stock  during any period in which the Company has  deferred  payment of
interest on its subordinated deferrable interest debentures.

Long-Term Debt. Total  long-term  debt  maturing in the period  1997-2001  is as
follows:

          1997                 $106,256,000
          1998                  200,000,000
          1999                  225,000,000
          2000                  275,000,000
          2001                  300,000,000

Note C   Lines of Credit

The Company has bank lines of credit for 1997  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.

Note D   Pension Benefits

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 subject to statutory
maximum (and  minimum)  limits.  Benefits for  management  and  bargaining  unit
employees are generally based on a final five-year average pay formula.

In  accordance  with SFAS No. 87,  "Employers'  Accounting  for  Pensions,"  the
Company uses the  projected  unit credit  method for  determining  pension cost.
Pension costs for 1996,  1995 and 1994 amounted to $73.2 million,  $11.4 million
and $38.7 million,  respectively,  of which $57.8 million for 1996, $8.9 million
for 1995 and $30.3  million for 1994 was charged to operating  expense.  Pension
costs reflect the  amortization of a regulatory  asset  established  pursuant to
SFAS No. 71 to offset the $33.3 million  increase in pension  obligations from a
special  retirement  program the Company offered in 1993, which provided special
termination  benefits as described in SFAS No. 88,  "Employers'  Accounting  for
Settlements   and   Curtailments  of  Defined  Benefit  Pension  Plans  and  for
Termination  Benefits."  Pension  cost for 1995  also  includes  an  actuarially
determined credit of $7.3 million representing a prepayment on one of the plans.
This credit reduced pension funding in 1996.

The Company is subject to 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  actuarial
recognition of investment  gains and losses over five years and a 10-year period
for amortization of unrecognized actuarial gains and losses.

The components of net periodic pension cost for 1996, 1995 and 1994 were as
follows:

(Millions of Dollars)                      1996        1995         1994
Service cost - benefits earned
    during the period                    $120.2       $ 98.2     $ 103.9
Interest cost on projected
    benefit obligation                    320.1        296.7       278.2
Actual return on plan assets             (593.6)      (865.8)       (3.4)
Unrecognized investment
    gain (loss) deferred                  217.6        521.6      (322.6)
Net amortization                            6.7        (41.5)      (17.4)
Net periodic pension cost                  71.0          9.2*       38.7
Amortization of regulatory asset            2.2          2.2        --
Total pension cost                       $ 73.2       $ 11.4     $  38.7
*  Includes a prepayment credit of $7.3 million.



<PAGE>
                                       60


The funded  status of the pension  plans as of December 31, 1996,  1995 and 1994
was as follows:

(Millions of Dollars)                     1996             1995            1994
Actuarial present value of
  benefit obligation:
    Vested                            $3,525.9         $3,319.2        $2,813.0
    Nonvested                            190.5            267.9           189.6
    Accumulated to date                3,716.4          3,587.1         3,002.6
    Effect of projected future
      compensation levels                986.6          1,070.3           786.0
    Total projected obligation         4,703.0          4,657.4         3,788.6
Plan assets at fair value              5,269.3          4,775.8         4,046.7
Plan assets less projected
    benefit obligation                   566.3            118.4           258.1
Unrecognized net gain                   (703.8)          (240.3)         (401.1)
Unrecognized prior service cost*         100.1             85.3            93.9
Unrecognized net transition
    liability at January 1, 1987*         14.3             17.2            20.2
Accrued pension cost**                 $ (23.1)        $  (19.4)       $  (28.9)
* Being amortized over approximately 15 years.
**Accrued liability primarily for special retirement program, reduced in 1995 by
  a prepayment credit and increased in 1996 by the application of that credit.

To determine the present value of the projected benefit obligation in 1996, 1995
and 1994, discount rates of 7.25 percent, 7 percent and 8 percent, respectively,
were assumed. A weighted average rate of increase in future  compensation levels
of 5.8 percent and  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 stocks and bonds,
group  annuity  contracts  and  debt of the  United  States  government  and its
agencies.

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's policy is
to fund in external trusts the actuarially  determined  annual costs for retiree
health and life insurance subject to statutory maximum limits.

The Company is subject to the PSC Policy (see Note D) which  requires  actuarial
recognition of investment  gains and losses over five years and a 10-year period
for  amortization  of unrecognized  actuarial gains and losses.

The cost to the Company  for retiree  health  benefits  for 1996,  1995 and 1994
amounted to $89.2  million,  $65.5 million and $67.1 million,  respectively,  of
which $70.5 million for 1996,  $51.6 million for 1995 and $52.7 million for 1994
was charged to operating  expense.  The cost of the retiree life  insurance plan
for 1996,  1995 and 1994  amounted  to $22.8  million,  $18.0  million and $21.6
million,  respectively,  of which $18.0 million for 1996, $14.2 million for 1995
and $17.0 million for 1994 was charged to operating expense.

The components of  postretirement  benefit (health and life insurance) costs for
1996, 1995 and 1994 were as follows:

(Millions of Dollars)                             1996       1995          1994
Service cost - benefits earned
  during the period                             $ 17.4      $10.7         $11.5
Interest cost on accumulated
  postretirement benefit obligation               68.9       61.2          56.9
Actual return on plan assets                     (51.3)     (60.8)         (8.4)
Unrecognized investment gain
  (loss) deferred                                 23.5       40.4          (5.7)
Amortization of transition
  obligation and unrecognized
  net loss                                        53.5       32.0          34.4
Net periodic postretirement
  benefit cost                                  $112.0      $83.5         $88.7











The following table sets forth the program's funded status at December 31, 1996,
1995 and 1994:

(Millions of Dollars)                            1996        1995          1994
Accumulated postretirement
 benefit obligation:
  Retirees                                     $471.1     $  447.7       $413.9
  Employees eligible to retire                  248.8        250.7        167.2
  Employees not eligible to retire              279.2        305.6        204.5
  Total projected obligation                    999.1      1,004.0        785.6
Plan assets at fair value                       444.2        322.2        219.1
Plan assets less accumulated
  postretirement benefit obligation            (554.9)      (681.8)      (566.5)
Unrecognized net loss                           139.9        240.8         11.1
Unrecognized net transition
  liability at January 1, 1993*                 415.0        441.0        555.4
Accrued postretirement
  benefit cost                                $    0       $   0         $  0
*  Being amortized over a period of 20 years.

To determine the accumulated postretirement benefit obligation in 1996, 1995 and
1994,  discount  rates of 7.25 percent,  7 percent and 8 percent,  respectively,
were  assumed.  The  assumed  long-term  rate of return on plan  assets  was 8.5
percent for these years.  The health care cost trend rate assumed for 1996 was 9
percent,  for 1997, 8.5 percent, and then declining one-half percent per year to
5 percent for 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 $125.7 million
and the service cost and interest  component of the net periodic  postretirement
benefit cost would increase by $13.2 million.

<PAGE>
                                       61



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

Note F   Contingencies

Indian Point. Nuclear generating units similar in design to the Company's Indian
Point 2 unit have  experienced  problems  that  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 and  current  Nuclear
Regulatory  Commission  criteria,  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 1996 dollars) to require additional  expenditures of approximately
$110  million   (exclusive  of  replacement   power  costs)  and  an  outage  of
approximately four 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,  1996 the highest  amount  which  could be  assessed  for losses  during the
current policy year under all of the policies was $29 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.

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, 1996 of  approximately  $23.1  million.
There will be additional  costs with respect to these and possibly  other sites,
the materiality of which is not presently determinable.

DEC  Settlement. In 1994 the Company agreed to a consent order  settling a civil
administrative   proceeding   instituted  by  the  DEC  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, 1996 the Company had an accrued  liability  of
$17.3 million for these sites. Expenditures for environment-related  projects in
the five years  1997-2001,  including  expenditures  to comply  with the consent
order, are currently estimated at $147 million.  There will be additional costs,
including costs arising out of the compliance audit, the materiality of which is
not presently determinable.

Asbestos  Claims. Suits have been  brought in New York State and federal  courts
against  the  Company  and  many  other  defendants,   wherein  several  hundred
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. 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.


<PAGE>
                                       62



Note G   Non-Utility Generators (NUGs)

The  Company  has  contracts  with NUGs for  approximately  2,100 MW of electric
generating  capacity.  Under the 1995 electric rate  agreement,  payments by the
Company under the contracts are reflected in rates.  Assuming performance by the
NUGs, the Company is obligated over the terms of these  contracts  (which extend
for various periods,  up to 2036) 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.

Capacity  and other  fixed  (non-energy)  payments  under  these  contracts  are
estimated  for 1997-2001 to be $336 million,  $340 million,  $356 million,  $413
million and $419 million. Such payments gradually increase to approximately $500
million in 2013, and thereafter decline significantly.

Energy payments under the contracts for 1997-1999  (assuming  performance by the
NUGs) 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   Stock-Based Compensation

Under the 1996 Stock  Option  Plan,  options may be granted to officers  and key
employees for up to 10,000,000 shares of the Company's common stock. In May 1996
the Company  granted  options for 704,200 shares at an exercise price of $27.875
per share. These options become exercisable three years after the grant date and
generally remain exercisable until ten years from the grant date.

As permitted by SFAS No.  123,  "Accounting  for Stock-Based  Compensation," the
Company  has  elected to follow  Accounting  Principles  Board  Opinion  No. 25,
"Accounting for Stock Issued to Employees" (APB 25) and related  interpretations
in accounting for its employee stock options. Under APB 25, because the exercise
price of the Company's  employee  stock  options  equals the market price of the
underlying stock on the date of grant, no compensation expense is recognized.

Disclosure of pro-forma  information regarding net income and earnings per share
is required by SFAS No. 123.  This  information  has been  determined  as if the
Company had accounted for its employee stock options under the fair value method
of that  statement.  The fair  value of these  options,  $2.49  per  share,  was
estimated at the date of grant using the Black-Scholes option pricing model with
the  following  weighted-average  assumptions  for  grants  in  1996:  risk-free
interest  rate of 6.74%;  expected life of eight years;  expected  volatility of
16.28%; and a dividend yield of 7.46%.

Had the  Company  used  SFAS No.  123,  earnings  per  share  for 1996  would be
unaffected and pro-forma net income for common stock would be  $687,938,000,  or
$231,000 less than the amount reported.

Note I   Federal Income Tax

The net revenue  requirements  for the future  federal  income tax  component of
accumulated  deferred federal income taxes (see Note A) at December 31, 1996 and
1995 are shown on the following table:

(Millions of Dollars)                                  1996                1995
Future federal income tax liability
    Temporary  differences  between  the  book
     and  tax  bases  of  assets  and
    liabilities:
      Property related                               $5,595.0         $ 5,513.3
      Reserve for injuries and damages                  (55.7)            (49.2)
      Other                                              16.7              54.5
      Total                                           5,556.0           5,518.6
    Future federal income tax computed
      at statutory rate - 35%                         1,944.6           1,931.5
Less: Accumulated deferred federal income
      taxes previously recovered                      1,304.8           1,254.0
Net future federal income tax expense
    to be recovered                                     639.8             677.5
Net revenue requirements for above
    (Regulatory asset-future federal
    income taxes)*                                      984.3           1,042.3
Add: Accumulated deferred federal income
      taxes previously recovered
         Depreciation                                 1,115.5           1,046.8
         Unbilled revenues                              (94.6)            (87.1)
         Advance refunding of long-term debt             32.7              32.4
         Other                                          251.2             261.9
      Subtotal                                        1,304.8           1,254.0
Total accumulated deferred
    federal income tax                               $2,289.1          $2,296.3
  * Net  revenue  requirements  will be offset by the  amortization  to  federal
income tax expense of  accumulated  deferred  investment  tax  credits,  the tax
benefits of which the Company has already  realized.  Including  the full effect
therefrom,  the net revenue  requirements related to future federal income taxes
at  December  31,  1996  and  1995  are  $811.8  million  and  $860.8   million,
respectively.

<PAGE>
                                       63

<TABLE>


Note I   Federal Income Tax, continued

Year Ended December 31 (Thousands of Dollars)            1996              1995                1994
<S>                                               <C>               <C>                 <C>  
Charged to: Operations                            $   397,160       $   396,560         $   438,160
            Other Income                                 (970)            1,060                 430
Total federal income tax                              396,190           397,620             438,590

Reconciliation of reported net income
  with taxable income
Federal income tax - current                          355,590           328,600             374,500
Federal income tax - deferred                          49,510            78,330              73,710
Investment tax credits deferred                        (8,910)           (9,310)             (9,620)
Total federal income tax                              396,190           397,620             438,590

Net income                                            694,085           723,850             734,270

Income before federal income tax                    1,090,275         1,121,470           1,172,860

Effective federal income tax rate                       36.3%             35.5%               37.4%

Adjustments decreasing (increasing)
  taxable income
Tax depreciation in excess of book depreciation:
    Amounts subject to normalization                  201,760           202,230             218,181
    Other                                             (99,576)          (85,538)            (94,813)
Deferred recoverable fuel costs                        42,008            61,937             (20,132)
Regulatory accounts receivable                         51,878           (32,827)            (70,771)
Excess research and development                       (13,025)           (2,969)             (1,284)
Pension and other postretirement benefit              (34,136)           38,102               3,535
Power contract termination costs                      (38,759)          (56,397)             77,699
Other - net                                           (45,729)           25,356             (12,824)
Total                                                  64,421           149,894              99,591

Taxable income                                      1,025,854           971,576           1,073,269

Federal income tax - current
Amount computed at statutory rate - 35%               359,049           340,052             375,644
Tax credits                                            (3,459)          (11,452)             (1,144)
Total                                                 355,590           328,600             374,500
Charged to: Operations                                357,000           328,200             374,160
            Other Income                               (1,410)              400                 340
Total                                                 355,590           328,600             374,500

Federal income tax - deferred
Charged to: Operations                                 49,070            77,670              73,620
            Other Income                                  440               660                  90
Total                                               $  49,510       $    78,330          $   73,710


</TABLE>

<PAGE>
                                       64



Note J   Financial Information by Business Segments (a)

<TABLE>

                                             Electric                                               Steam
(Thousands of Dollars)          1996             1995             1994            1996             1995         1994
<S>                       <C>              <C>               <C>            <C>             <C>           <C>

Operating revenues ....   $5,552,247       $5,401,524        $5,152,351    $   405,040      $   335,694   $   343,916
Operating expenses
Purchased power ........   1,269,092        1,107,223           787,455          3,762               --           --
Fuel ...................     377,351          354,086           410,173        195,924          150,018       157,591
Other operations
    and maintenance* ...   1,331,801        1,372,715         1,372,865         83,837           79,929        80,035
Depreciation and
    amortization .......     425,397          393,382           364,988         15,900           13,064        10,961
Taxes, other than
    federal income .....     980,309          951,095           955,850         51,361           45,788        46,178
Federal income tax .....     330,103          339,863           379,584         14,131           12,598        11,577
Total operating
    expenses* ..........   4,714,053        4,518,364         4,270,915        364,915          301,397       306,342
Operating income .......     838,194          883,160           881,436         40,125           34,297        37,574
Construction
    expenditures .......     515,006          538,454           587,189         38,290           27,559        44,957
Net utility plant** ....   9,150,261        9,027,031         8,874,341        458,019          399,028       378,748
Fuel ...................      64,231           40,444            50,821            478               62           62
Other identifiable
    assets .............   1,703,906        1,724,005         1,899,182         42,817           51,969        48,141


*Intersegment rentals included in segments' income but eliminated for total Company
    Operating revenues    $   11,130       $   12,116        $   11,879    $     1,491      $      1,561  $     1,409
    Operating expenses         2,472            2,513             2,331         12,190            13,102       12,733

 
                                                 Gas                                     Total Company
                                1996            1995              1994            1996             1995          1994

Operating revenues*       $1,017,124       $ 815,307         $ 891,897     $ 6,959,736      $ 6,536,897   $ 6,373,086
Operating expenses
Purchased power .......           --              --                --       1,272,854        1,107,223       787,455
Fuel ..................           --              --                --         573,275          504,104       567,764
Gas purchased
    for resale ........      418,271         259,789           341,204         418,271          259,789       341,204
Other operations 
    and maintenance* ..      221,011         214,818           214,451       1,621,974        1,651,834     1,652,273
Depreciation and
    amortization ......       55,115          49,330            46,407         496,412          455,776       422,356
Taxes, other than
    federal income ....      134,529         123,349           125,663       1,166,199        1,120,232     1,127,691
Federal income tax ....       52,926          44,099            46,999         397,160          396,560       438,160
Total operating
    expenses* .........      881,852         691,385           774,724       5,946,145        5,495,518     5,336,903
Operating income ......      135,272         123,922           117,173       1,013,591        1,041,379     1,036,183
Construction
    expenditures ......      121,937         126,790           125,384         675,233          692,803       757,530
Net utility plant** ...    1,459,030       1,388,344         1,308,119      11,067,310       10,814,403    10,561,208
Fuel and gas
    in storage ........       44,979          26,452            50,698         109,688           66,958       101,581
Other identifiable
    assets ............      197,033         177,374           151,628       1,943,756        1,953,348     2,098,951
Other corporate assets                                                         936,431        1,115,181       966,624
Total assets                                                               $14,057,185      $13,949,890   $13,728,364

* Intersegment rentals included in segments' income but eliminated for total Company
    Operating revenues   $     2,054     $     1,951       $     1,790     $    14,675      $    15,628   $    15,078
    Operating expenses            13              13                14          14,675           15,628        15,078

**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.

</TABLE>


(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>
                                       65





                                                                 SCHEDULE VIII



                CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.

                      VALUATION AND QUALIFYING ACCOUNTS
                         YEAR ENDED DECEMBER 31, 1996
                            (Thousands of Dollars)




COLUMN A            COLUMN B            COLUMN C         COLUMN D      COLUMN E
                                       Additions
                                      (1)      (2)
                    Balance at    Charged to  Charged to              Balance at
                    Beginning     Costs and     Other                     End of
Description         of Period      Expenses    Accounts   Deductions      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       $ 30,771         -      $ 30,771*     $ 21,600

Other                  -              -            -           -             -



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


<PAGE>
                                       66





                                                                 SCHEDULE VIII



                CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.

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




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



<PAGE>
                                       67





                                                                 SCHEDULE VIII



                CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.

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




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



<PAGE>
                                       68





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  19,  1997.  The  proxy  statement  is to be  filed  pursuant  to
Regulation 14A not later than 120 days after December 31, 1996, 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>
                                       69






                               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, 1996 and 1995

            Consolidated Income Statement for the years ended
               December 31, 1996, 1995 and 1994

            Consolidated Statement of Cash Flows for the years ended
               December 31, 1996, 1995 and 1994

            Consolidated Statement of Capitalization at December 31,
               1996 and 1995

            Consolidated Statement of Retained Earnings for the years
               ended December 31, 1996, 1995 and 1994

            Notes to Consolidated Financial Statements


      2.   List of Financial Statement Schedules

            Valuation and Qualifying Accounts  (Schedule VIII)




<PAGE>
                                       70




      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,  (File No.  1-1217) 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,  (File No.  1-1217) as Exhibit
            4(e).)

            *3.2  By-laws of the Company, effective as of January 1, 1997.

            4.1 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 quarterly period ended June 30, 1990 (File No.
            1-1217) as Exhibit 4(a)(1).)


<PAGE>
                                       71






            4.2   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)

            4.3  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 (File No.
            1-1217) as Exhibit 4(f).)

            4.4   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

            4.5 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 quarterly  period ended June 30, 1990 (File No. 1-1217)
            as Exhibit 4(b)(1).)


<PAGE>
                                       72






            4.6 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)

            4.7  Indenture  of Trust,  dated as of  December  1,  1992,  between
            NYSERDA and Morgan  Guaranty.  (Designated  in the Company's  Annual
            Report on Form 10-K for the year ended December 31, 1992 (File No.
            1-1217) as Exhibit 4(i).)

            4.8 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

            4.9 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 (File No. 1-1217)
            as Exhibit 4(h).)

            4.10 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.  (Designated in
            the Company's Annual Report on Form 10-K for the year ended December
            31, 1995 (File No. 1-1217) as Exhibit 4.13.)



<PAGE>
                                       73






      4.11  The following Forms of the Company's Debentures:

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

            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
            7 3/4%,  Series 1996 A        8-K   4/24/96         4
            Floating Rate Series 1996 B   8-K   11/25/96        4

            4.12  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,
            (File No. 1-1217) 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.)

            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 (File  No.1-1217)  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.)


<PAGE>
                                       74






            *10.5 The Con Edison Thrift Savings Plan for Management
            Employees and Tax Reduction Act Stock Ownership Plan, as
            amended and restated.

            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 (File No. 1-1217) 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(File No.
            1-1217) 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  (File No.  1-1217) 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 quarterly period ended June 30, 1990 (File No.
            1-1217) as Exhibit 10.)

            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  quarterly
            period ended September 30, 1991 (File No. 1-1217) 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
            quarterly  period  ended  September  30,  1992  (File No.  1-1217) s
            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 (File No. 1-1217) 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 (File No. 1-1217) as Exhibit
            10.1.)



<PAGE>
                                       75





            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 (File No.  1-1217) 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 (File No. 1-1217) as
            Exhibit 10.3.)

            10.16 Amendment,  dated July 23, 1996, 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 June 30, 1996 (File No. 1-1217) as Exhibit 10.2.)

            10.17 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, (File No. 1-1217) as Exhibit 10(q).)

            10.18 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
            (File No. 1-1217) as Exhibit 10(r).)

            10.19 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
            (File No. 1-1217) as Exhibit 10(s).)

            10.20 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
            (File No. 1-1217) as Exhibit 10.1.)

            10.21 Amendment No. 1, dated December 29, 1995, to the
            Consolidated Edison Retirement Plan for Management
            Employees. (Designated in the Company's Annual Report on
            Form 10-K for the year ended December 31, 1995 (File No.
            1-1217) as Exhibit 10.29.)


<PAGE>
                                       76






            *10.22 Amendment No. 2, dated July 1,1996, to the
            Consolidated Edison Retirement Plan for Management Employees.

            10.23 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
            (File No. 1-1217) as Exhibit 10(cc).)

            *10.24 Amendment No. 1, dated March 21,1997, to the Con
            Edison Supplemental Retirement Income Plan.

            10.25 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 (File No. 1-1217) as Exhibit 10(ee).)

            10.26 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 quarterly period
            ended September 30, 1990 (File No. 1-1217) as Exhibit 19(c).)

            10.27 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 (File No. 1-1217) as Exhibit 10(gg).)

            10.28 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 (File No. 1-1217) as Exhibit 10(hh).)

            10.29 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
            (File No. 1-1217) as Exhibit 10(aa).)

            10.30 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 (File No. 1-1217)
            as Exhibit 10(bb).)

            10.31 Amendment, dated December 29, 1995, to the Con
            Edison Discount Stock Purchase Plan.  (Designated in the
            Company's Annual Report on Form 10-K for the year ended
            December 31, 1995 (File No. 1-1217) as Exhibit 10.38.)

            10.32 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
            quarterly period ended June 30, 1991 (File No. 1-1217)
            as Exhibit 19.)


<PAGE>
                                       77






            10.33 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 quarterly period
            ended March 31, 1993 (File No. 1-1217) as Exhibit 10.)

            10.34 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 quarterly period
            ended September 30, 1993 (File No. 1-1217) as Exhibit 10.2.)

            10.35 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 (File No. 1-1217)
            as Exhibit 10(ll).)

            10.36 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(File No. 1-1217)  as Exhibit 10.3.)

            10.37 Amendment No. 2, dated December 28, 1994, to the
            Consolidated Edison Retiree Health Program for
            Management Employees. (Designated in the Company's
            Annual Report on Form 10-K for the year ended December
            31, 1995 (File No. 1-1217) as Exhibit 10.44.)

            10.38 Amendment No. 3, dated December 29, 1995, to the
            Consolidated Edison Retiree Health Program for
            Management Employees. (Designated in the Company's
            Annual Report on Form 10-K for the year ended December
            31, 1995 (File No. 1-1217) as Exhibit 10.45.)

            *10.39 Amendment No. 4, dated July 1, 1996, to the
            Consolidated Edison Retiree Health Program for
            Management Employees.

            10.40  Employment  Agreement,  dated November 28, 1995,  between the
            Company and Peter J. O'Shea, Jr. (Designated in the Company's Annual
            Report on Form 10-K for the year ended December 31, 1995 (File No.
            1-1217) as Exhibit 10.46.)

            10.41 Consolidated Edison Company of New York, Inc. 1996
            Stock Option Plan. (Designated in the Company's Annual
            Report on Form 10-K for the year ended December 31, 1995
            (File No. 1-1217) as Exhibit 10.47.)

            10.42  Agreement and Settlement,  dated March 12, 1997,  between the
            Company  and  the  Staff  of  the  New  York  State  Public  Service
            Commission  (without  Appendices).   (Designated  in  the  Company's
            Current Report on Form 8-K, dated March 13, 1997,  (File No. 1-1217)
            as Exhibit 10.)


<PAGE>
                                       78






            *12 Statement of  computation  of ratio of earnings to fixed charges
            for the years ended December 31, 1996, 1995, 1994, 1993 and 1992.

            *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.  (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




(b)   Reports on Form 8-K:

      The Company filed Current  Reports on Form 8-K,  dated October 1, 1996 and
March 13, 1997,  reporting (under Item 5) matters discussed under "Liquidity and
Capital  Resources - Competition and Industry  Restructuring  and PSC Settlement
Agreement"  in Item 7. The  Company  filed a Current  Report on Form 8-K,  dated
November 25, 1996,  reporting  (under Item 5) the December 12, 1996 sale of $150
million aggregate principal amount of its Floating Rate Debentures,  Series 1996
B and the November 25, 1996  rejection by the Supreme  Court of the State of New
York,  Albany County,  of a challenge by the Company and other  utilities to the
May 1996 PSC order discussed under "Liquidity and Capital Resources  Competition
and Industry  Restructuring and PSC Settlement Agreement" in Item 7. The Company
filed no other Current Reports on Form 8-K during the quarter ended December 31,
1996.



<PAGE>
                                       79






                                  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, 1997                      By    Joan S. Freilich
                                                Joan S. Freilich
                                                Senior Vice President
                                                 and 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, 1997          Eugene R. McGrath*      Chairman of the Board,
                                                 President, Chief Executive
                                                 Officer and Trustee
                                                (Principal Executive Officer)

March 28, 1997          Joan S. Freilich*       Senior Vice President
                                                 and Chief Financial Officer
                                                (Principal Financial Officer)

March 28, 1997          John F. Cioffi*         Vice President, Controller
                                                 and Chief Accounting Officer
                                                (Principal Accounting Officer)

                        E. Virgil Conway*       Trustee
                        Ruth M. Davis*          Trustee
                        Ellen V. Futter*        Trustee
                        Arthur Hauspurg*        Trustee
                        Sally Hernandez-Pinero* Trustee
                        Peter W. Likins*        Trustee
                        Donald K. Ross*         Trustee
                        Robert G. Schwartz*     Trustee
                        Richard A. Voell*       Trustee
                        Myles V. Whalen, Jr.*   Trustee



March 28, 1997    *By   Joan S. Freilich        Attorney-in-Fact
                        Joan S. Freilich