S E C U R I T I E S  A N D  E X C H A N G E  C O M M I S S I O N

                             WASHINGTON, D.C. 20549



                                    FORM 10-K


            |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE

                 SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995

                                       OR

             |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)

            OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

                          COMMISSION FILE NUMBER 1-3571



                          LONG ISLAND LIGHTING COMPANY

               INCORPORATED PURSUANT TO THE LAWS OF NEW YORK STATE


      INTERNAL REVENUE SERVICE - EMPLOYER IDENTIFICATION NUMBER 11-1019782

              175 EAST OLD COUNTRY ROAD, HICKSVILLE, NEW YORK 11801

                                  516-755-6650

               SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF
                                    THE ACT:

                       Title of each class so registered:


Common Stock ($5 par)
Preferred Stock ($100 par, cumulative):

Series B, 5.00%      Series E, 4.35%            Series I, 5 3/4%, Convertible
                     Series CC, 7.66%


Preferred Stock ($25 par, cumulative):
Series AA, 7.95%     Series GG, $1.67          Series QQ, 7.05%

                     Series NN, $1.95



General and Refunding Bonds:

   8 3/4% Series Due 1996      7.85% Series Due 1999      7.90% Series Due 2008
   8 3/4% Series Due 1997     8 5/8% Series Due 2004     9 3/4% Series Due 2021
   7 5/8% Series Due 1998      8.50% Series Due 2006     9 5/8% Series Due 2024


Debentures:
  7.30% Series Due 1999       7.05%  Series Due 2003    8.90% Series Due 2019
  7.30% Series Due 2000       7.00%  Series Due 2004    9.00% Series Due 2022
  6.25% Series Due 2001       7.125% Series Due 2005    8.20% Series Due 2023
                              7.50%  Series Due 2007

         NAME OF EACH EXCHANGE ON WHICH EACH CLASS IS  REGISTERED:  The New York
Stock  Exchange and the Pacific Stock  Exchange are the only  exchanges on which
the Common Stock is registered. The New York Stock Exchange is the only exchange
on which each of the other securities listed above is registered.

        SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None

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

                                 Yes |X| No |_|

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

         The aggregate  market value of the Common Stock held by  non-affiliates
of the Company at January  31, 1996 was  $2,038,959,770.  The  aggregate  market
value of Preferred  Stock held by  non-affiliates  of the Company at January 31,
1996,  established by Lehman  Brothers based on the average bid and asked price,
was $642,932,411.

   COMMON STOCK ($5 PAR) - SHARES OUTSTANDING AT JANUARY 31, 1996: 119,938,810

         The Company's  proxy statement for its Annual Meeting of Shareowners to
be held on May 9, 1996 has been  incorporated by reference into Part III of this
Form 10-K to provide  information  required in Item 10 (Directors  and Executive
Officers of the Company) as to Directors, Item 11 (Executive Compensation), Item
12 (Security  Ownership of Certain Beneficial Owners and Management) and Item 13
(Certain Relationships and Related Transactions).


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                                TABLE OF CONTENTS


ABBREVIATIONS.......................................................... iii

                                     PART I

ITEM 1. BUSINESS..........................................................1
         The Company......................................................1
         Territory........................................................1
         Segments of Business.............................................1
         Employees........................................................2
         Regulation and Accounting Controls...............................2
                  Long Island Power Authority Proposed Plan...............3
         Competitive Environment..........................................3
         Electric Operations..............................................4
                  General  ...............................................4
                  System Requirements, Energy Available and Reliability...5
                  Energy Sources..........................................5
                           Oil      ......................................5
                           Natural Gas....................................6
                           Nuclear  ......................................6
                           Purchased Power................................6
                           Interconnections...............................7
                  Conservation Services...................................7
                  The 1989 Settlement.....................................7
                  Electric Rates..........................................8
         Gas Operations...................................................8
                  General  ...............................................8
                  Gas System Requirements.................................8
                           Peak Day Capability............................8
                           Firm Transportation Capacity...................9
                                    Storage...............................9
                           Cogen Deliveries ..............................9
                           Peak Shaving..................................10
                           Firm Gas Supply...............................10
                  Gas Rates..............................................10
                  Other Activities.......................................10
                  Recovery of Transition Costs...........................10
         Environment.....................................................11
                  General  ............................................. 11
                  Air      ..............................................11
                  Water    ..............................................13
                  Land     ..............................................13
                  Nuclear Waste..........................................16
         The Company's Securities........................................17
                  General  ..............................................17
                  The First Mortgage.....................................18
                  The G&R Mortgage.......................................18
                  Unsecured Debt.........................................19
                  Equity Securities......................................20
                           Preferred Stock...............................20
                           Preference Stock..............................20
                           Common Stock..................................21
         Executive Officers of the Company...............................21
         Capital Requirements, Liquidity and Capital Provided............26

ITEM 2. PROPERTIES.......................................................26

ITEM 3. LEGAL PROCEEDINGS................................................26
         Shoreham .......................................................26
         Environmental...................................................27
         Human Resources.................................................27
         Other Matters...................................................28


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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............28

                                     PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
        MATTERS..........................................................29

ITEM 6. SELECTED FINANCIAL DATA..........................................30

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS....................................................35

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA......................59
         Statement of Income............................................ 60
         Balance Sheet...................................................61
         Statement of Retained Earnings..................................63
         Statement of Capitalization.....................................63
         Statement of Cash Flows.........................................65
         Notes to Financial Statements...................................66
         Report of Independent Auditors.................................105

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 
        FINANCIAL DISCLOSURE............................................106

                                    PART III

         ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY.......106

ITEM 11. EXECUTIVE COMPENSATION.........................................106

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.106

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................106

                                     PART IV

ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K 106
         List of Financial Statements....................................106
         List of Financial Statement Schedules...........................107
         List of Exhibits................................................108
         Reports on Form 8-K.............................................113
         Schedule II.....................................................114

SIGNATURES...............................................................115



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                                  ABBREVIATIONS

         The following abbreviations are sometimes used in this Annual Report.


ACO............  Administrative Consent Order
AFC............  Allowance For Funds Used During Construction
ALJ............  Administrative Law Judge
BFC............  Base Financial Component
BVPA...........  Bondable Value of Property Additions
DEC............  New York State Department of Environmental Conservation
DOE............  United States Department of Energy
DSM............  Demand Side Management
Dth............  Dekatherms
EFRBs..........  Electric Facilities Revenue Bonds
EPA............  United States Environmental Protection Agency
FCA............  Fuel Cost Adjustment
FERC...........  Federal Energy Regulatory Commission
First Mortgage.  Indenture of Mortgage and Deed of Trust dated as of
                 September 1, 1951
FRA............  Financial Resource Asset
G&R Bonds......  General and Refunding Bonds
G&R Mortgage...  General and Refunding Indenture dated as of June 1, 1975
GAAP...........  Generally Accepted Accounting Principles
GWh............  Gigawatt Hour
IPP............  Independent Power Producers
kW.............  Kilowatts
kWh............  Kilowatt hour
LIPA...........  Long Island Power Authority
LRPP...........  Lilco Ratemaking and Performance Plan
MW.............  Megawatts
NMPC...........  Niagara Mohawk Power Corporation
NMP2...........  Nine Mile Point Nuclear Power Station, Unit 2
NRC............  Nuclear Regulatory Commission
NYPA...........  New York Power Authority
NYPP...........  New York Power Pool
NYSEG..........  New York State Electric & Gas Corporation
NYSERDA........  New York State Energy Research and Development Authority
PCRBs..........  Pollution Control Revenue Bonds
PILOTs.........  Payments in-lieu-of-taxes
PRP............  Potentially Responsible Party
PSC............  Public Service Commission of the State of New York
QF.............  Qualified Facilities
RMA............  Rate Moderation Agreement
RMC............  Rate Moderation Component
Shoreham.......  Shoreham Nuclear Power Station




                                       iii

<PAGE>



                      A LISTING OF ABBREVIATIONS FREQUENTLY
                        USED IN THIS REPORT MAY BE FOUND
                     IMMEDIATELY AFTER THE TABLE OF CONTENTS

                                     PART I




ITEM 1.   BUSINESS

THE COMPANY:

Long Island  Lighting  Company (the Company) was  incorporated in 1910 under the
Transportation  Corporations Law of the State of New York and supplies  electric
and gas service in Nassau and Suffolk Counties and to the Rockaway  Peninsula in
Queens County,  all on Long Island (L.I.),  New York. The mailing address of the
Company is 175 East Old Country Road, Hicksville, New York 11801 and its general
telephone number is (516)755-6650.

TERRITORY:

The Company's  service  territory covers an area of  approximately  1,230 square
miles.  The  population  of the service area,  according to the  Company's  1995
estimate,  is 2.7 million persons,  including  approximately  98,000 persons who
reside  in  Queens  County  within  the City of New  York.  The 1995  population
estimate reflects a 0.3% increase since the 1990 census.

Approximately  80% of all workers  residing in Nassau and Suffolk  Counties  are
employed within the two counties. In 1995 total  non-agricultural  employment in
Nassau and Suffolk  Counties  increased by  approximately  7,800  positions,  an
employment increase of 0.7%.

The Company serves  approximately 1 million electric  customers of which 915,000
are residential. The Company receives approximately 49% of its electric revenues
from residential customers and 48% from  commercial/industrial  customers and 3%
from sales to other  utilities and public  authorities.  The Company also serves
approximately   453,000  gas  customers,   408,000  of  which  are  residential,
accounting  for 62% of the gas  revenues,  with the balance of the gas  revenues
made up by the commercial/industrial customers and off-system sales.

SEGMENTS OF BUSINESS:

For  information  concerning  the  Company's  electric  and  gas  financial  and
operating  results,  see  Item  7,  "Management's  Discussion  and  Analysis  of
Financial  Condition and Results of Operations"  for the Year Ended December 31,
1995,  "Selected  Financial  Data" and Notes 2, 3, and 11 of Notes to  Financial
Statements for the Year Ended December 31, 1995.

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<PAGE>



EMPLOYEES:

As of December 31, 1995,  the Company had 5,688  full-time  employees,  of which
2,347 belong to Local 1049 and 1,342  belong to Local 1381 of the  International
Brotherhood of Electrical Workers.  Effective February 14, 1996, the Company and
these unions agreed upon  contracts  which will expire on February 13, 2001. The
contracts  provide,  among other things,  for wage increases totaling 15.5% over
the term of the agreements.

REGULATION AND ACCOUNTING CONTROLS:

The Company is subject to  regulation  by the Public  Service  Commission of the
State  of New  York  (PSC)  with  respect  to  rates,  issuances  and  sales  of
securities,  adequacy and  continuance of service,  safety and siting of certain
facilities,  accounting,  conservation of energy,  management  effectiveness and
other  matters.  To ensure  that its  accounting  controls  and  procedures  are
consistently  maintained,  the Company  actively  monitors  these  controls  and
procedures.  The Audit Committee of the Company's Board of Directors, as part of
its responsibilities, periodically reviews this monitoring program.

New York law requires  that all  utilities be  periodically  audited to identify
those aspects of their operations, if any, which are in need of improvement. The
results  of  the  PSC  Internal  Control   Practices  audit  and  the  Executive
Compensation  audit were issued  during  1995.  The Company is in the process of
implementing improvements to address the audit findings.

The Company is also subject,  in certain of its activities,  to the jurisdiction
of the  United  States  Department  of  Energy  (DOE)  and  the  Federal  Energy
Regulatory Commission (FERC). In addition to its accounting  jurisdiction,  FERC
has jurisdiction  over the rates the Company may charge for the sale of electric
energy  for  resale in  interstate  commerce,  including  the rates the  Company
charges for electricity sold to municipal  electric systems within the Company's
territory,  and for the transmission,  through the Company's system, of electric
energy to other utilities or certain industrial customers. It is in the exercise
of this  jurisdiction  over  transmission  that  FERC is  currently  considering
certain  issues  relating  to  competition  in  the  electric  industry.  For  a
discussion of these FERC  proceedings  see Item 7  "Management's  Discussion and
Analysis of Financial  Condition and Results of  Operations"  for the Year Ended
December  31, 1995 under the heading  "Competitive  Environment".  FERC also has
some  jurisdiction  over a portion of the Company's gas supplies and substantial
jurisdiction over transportation to the Company of its gas supplies.

Operation of Nine Mile Point Nuclear  Power  Station,  Unit 2 (NMP2),  a nuclear
facility in which the Company has an 18%  interest,  is subject to regulation by
the Nuclear Regulatory Commission (NRC).


                                        2

<PAGE>




LONG ISLAND POWER AUTHORITY PROPOSED PLAN:

A  discussion  of the  Long  Island  Power  Authority's  (LIPA)  proposed  plan,
regarding the  restructuring/acquisition  of the Company,  appears in Note 10 of
Notes to Financial Statements for the Year Ended December 31, 1995.

COMPETITIVE ENVIRONMENT:

A discussion of the  competitive  issues the Company faces appears in Note 10 of
Notes to Financial Statements for the Year Ended December 31, 1995.


                                        3

<PAGE>



ELECTRIC OPERATIONS:

General

The Company's system energy  requirements are supplied from sources located both
on and off Long Island.

The  following  table  indicates  the  1995  summer  capacity  of the  Company's
generating  facilities,  Internal Combustion Units (IC) and facilities under its
control as reported to the New York Power Pool (NYPP) in December 1995:

                                                                          Mega-
Location of Units           Description            Fuel        Units      watts

COMPANY OWNED

Northport, L.I.             Steam Turbine          Dual*         2          781
                                                   Oil           2          740

Port Jefferson, L.I.        Steam Turbine          Oil           2          382

Glenwood, L.I.              Steam Turbine          Gas           2          221

Island Park, L.I.           Steam Turbine          Dual          2          386

Far Rockaway, L.I.          Steam Turbine          Dual          1          109

Throughout L.I.             IC Units               Dual         12          281
                                                   Oil          30        1,057

JOINTLY OWNED

NMP2 (18% Share)
Oswego, New York            Steam Turbine          Nuclear       1          203


OWNED BY THE NEW
YORK POWER AUTHORITY

Holtsville, L.I.           Combined Cycle          Dual          1          142

       Total                                                    55        4,302
                                                                ==        =====



*Dual - Oil or natural gas, whichever is more economical.

Additional  generating  facilities  owned by others,  such as independent  power
producers (IPPs) and cogenerators  located on Long Island and investor-owned and
public  electric  systems  located off Long  Island,  provide the balance of the
Company's energy supplies.

The maximum demand on the Company's  system to date was 4,077  Megawatts (MW) on
August 4, 1995,  representing 84% of its total available capacity of 4,873 MW on
that day, which included 713 MW of firm

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capacity  purchased from other sources.  By agreement with the NYPP, the Company
is required to maintain,  on a monthly basis,  an installed and contracted  firm
power reserve generating capacity equal to at least 18% of its actual peak load.
The Company is currently meeting this NYPP requirement.

System Requirements, Energy Available and Reliability

In 1995, system kilowatt hour (kWh) energy  requirements on the Company's system
were .2% lower than in 1994.  The  Company  forecasts a 0.1%  decrease  and 1.2%
increase,  relative to 1995's  experience in system energy  requirements for the
years  1996 and 1997,  respectively.  However,  for the  period  1998-2007,  the
Company forecasts an average annual growth rate in system energy requirements of
1.0%. With the  availability of electricity  provided by the Company's  existing
generating facilities,  including its portion of energy generated at NMP2 and by
power  purchased  from other  electric  systems  and certain  non-Company  owned
facilities located within the Company's service territory,  the Company believes
it has  adequate  generating  sources  to meet its energy  demands  for the next
several years.

The  percentages  of  total  energy  available  by  type of  fuel  for  electric
operations for the years 1995, 1994 and 1993 are as follows:

  Fuel Mix                                                   (Based on MW Hours)
                                            1995        1994         1993
Oil                                          17%         25%          34%
Natural Gas                                  36          23           19
Nuclear (NMP2)                                7           9            7
Purchased Power                              40          43           40
Total                                       100%        100%         100%

Energy Sources

Total energy  provided by oil and natural gas is generated on the  Company's own
system  while the nuclear  generation  is provided  from NMP2.  The total energy
provided by purchased power is described below.

Oil
In recent  years,  the Company has been able to reduce its oil  requirements  by
burning natural gas. Oil consumption in 1995 was 5.2 million barrels compared to
7.5  million  barrels  in  1994.  The  availability  and cost of oil used by the
Company are affected by factors beyond its control such as the international oil
market, environmental regulations, conservation measures and the availability of
alternative  fuels.  The  Company's  fuel oil is  supplied  principally  by five
suppliers.

For information concerning federal and other regulatory environmental

                                        5

<PAGE>



limitations  on fuel oil  burned by the  Company,  see  "Environment  -Air." For
additional  information concerning the recovery of electric fuel costs, see Note
1 of Notes to Financial Statements for the Year Ended December 31, 1995.

Natural Gas
Several of the  Company's  generating  stations  have the  capability of burning
either oil or natural gas. These dual-fired units enable the Company to burn the
most cost  efficient fuel thereby  reducing the Company's  dependency on oil. In
1995 the Company  completed the conversion of the second  dual-fired unit at the
Northport  Power  Station and began work on the  conversion  of two units at its
Port Jefferson Power Station. These two units have projected completion dates of
December 1996 and May 1997. Gas consumption in 1995 was 69.8 million  dekatherms
(Dth) compared to 44.3 million Dth in 1994. In 1995, 67% of the energy generated
by the  Company's  steam and internal  combustion  units was produced by burning
natural gas. In 1992, that percentage was approximately 33%.

Nuclear
The Company  holds an 18% interest in NMP2, a 1,143 MW nuclear  generating  unit
near Oswego,  New York.  The cotenants of NMP2, in addition to the Company,  are
Niagara  Mohawk Power  Corporation  (NMPC) (41%),  New York State Electric & Gas
Corporation  (18%),  Rochester  Gas and Electric  Corporation  (14%) and Central
Hudson Gas & Electric Corporation (9%).

For additional  information on NMP2 and nuclear plant insurance,  see Note 5 and
Note 10 of Notes to Financial Statements for the Year Ended December 31, 1995.

Purchased Power
To keep electric  rates as low as possible,  the Company  provides its customers
with the most economical  energy  available.  Often, this energy is generated at
more  economical  power plants within other electric  systems and transmitted to
the Company through its  interconnections.  In addition,  the Company  purchases
energy from sources located within its service territory  including the New York
Power Authority (NYPA)  Holtsville  facility,  IPPs and  cogenerators.  IPPs and
cogenerators   located   within  the  Company's   service   territory   provided
approximately  204 MW of capacity to the  Company in 1995.  Capacity  from these
sources is expected to remain at approximately the same level in 1996.

In 1995,  1994 and 1993,  IPPs and  cogenerators  provided  9.7%,  9.3% and 9.5%
respectively,  of the Company's total system energy available.  The Company does
not expect any new major IPPs or  cogenerators to be built on Long Island in the
foreseeable  future.  Among  the  reasons  supporting  this  conclusion  is  the
Company's  belief that the market for IPPs and  cogenerators to provide power to
the  Company's   remaining   commercial  and  industrial   customers  is  small.
Furthermore,  under  federal  law,  the  Company is  required to buy energy from
qualified

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producers at the Company's  long-range avoided costs. Current long-range avoided
cost estimates for the Company have significantly reduced the economic advantage
to entrepreneurs seeking to compete with the Company and with existing IPPs. For
additional  information  respecting  competitive issues facing the Company,  see
Item 7, "Management's Discussion and Analysis of Financial Condition and Results
of  Operations"  for  the  Year  Ended  December  31,  1995  under  the  heading
"Competitive Environment".

Interconnections
Five interconnections  allow for the transfer of electricity between the Company
and  members  of the NYPP and the New  England  Power  Pool.  Energy  from these
sources is transmitted  pursuant to  transmission  agreements  with NMPC,  NYPA,
Northeast  Utilities  Service  Company  (NUSCO),  a  co-owner  of one  of  these
interconnections, and Consolidated Edison Company of New York, Inc. (Con Edison)
and displaces  energy which would otherwise be generated on the Company's system
at a higher cost. The capacity of these interconnections is utilized for Company
requirements  including the  transmission  of the Company's  share of power from
NMP2, the  requirements  of Con Edison,  a co-owner with the Company of three of
these  interconnections,  and the requirements on Long Island of NYPA, the owner
of one of these interconnections.

Conservation Services

A  discussion  of  conservation   services  appears  in  Item  7,  "Management's
Discussion and Analysis of Financial  Condition and Results of  Operations"  for
the Year Ended December 31, 1995 under the heading "Conservation Services".

The 1989 Settlement

On February  28,  1989,  the Company and the State of New York  entered into the
1989 Settlement  resolving certain issues relating to the Company and providing,
among  other  matters,  for the  financial  recovery  of the Company and for the
transfer  of the  Shoreham  Nuclear  Power  Station  (Shoreham)  to LIPA for its
subsequent decommissioning.

A discussion of the 1989 Settlement and Shoreham decommissioning appears in Note
2 of Notes to Financial Statements for the Year Ended December 31, 1995.


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Electric Rates

A  discussion  of  electric  rates  appears  in  Note 3 of  Notes  to  Financial
Statements for the Year Ended December 31, 1995.

GAS OPERATIONS:

General

In 1995, the Company was an active  participant in proceedings before FERC in an
effort to reduce interstate pipeline charges, to improve operational tariffs and
to mitigate any adverse impact from interstate pipeline filings on the Company's
customers.  In addition,  in 1996, the Company will actively  participate in the
proceedings   before  the  PSC  in  an  attempt  to  positively   influence  the
establishment of the new competitive natural gas marketplace within the State of
New York.

Gas System Requirements

At December 31, 1995 and 1994, the Company had a monthly  average of 452,906 and
447,689 firm gas customers,  respectively.  The monthly average of space heating
customers was 280,479 and 273,633,  respectively  at December 31, 1995 and 1994.
Total  firm  sales  in 1995  were  approximately  58,704,000  Dth,  compared  to
58,889,000 Dth in 1994.  The maximum daily sendout  experienced on the Company's
gas system in 1995 was 564,874 Dth on February 6, 1995. The  forecasted  maximum
daily sendout for the 1995-96  winter season  (November 1 - March 31) is 622,000
Dth,  representing  87% of the Company's  per day  capability of 717,035 Dth for
this period.  The Company recovers the cost of its gas supply from its customers
through provisions in the Company's rate schedules.

Continuing  its recent  efforts to expand its base of customers,  the Company is
actively marketing its natural gas services to potential customers. In step with
regulatory  changes  in the  gas  industry,  the  Company  has  proposed  a firm
transportation  program  that will  enable  gas  customers  to choose  their gas
supplier.  The Company is educating  its customers to make them aware of all the
services  that  the  Company  provides.  In  addition,  the  Company's  proposed
transportation rates may attract new customers to the Company.

Another  growth area being  pursued is the Natural  Gas  Vehicle  (NGV)  market.
Although  recent changes in federal funding and mandates have made NGV promotion
more  difficult,  this market still has a high growth  potential,  especially in
large  fleet  applications.  NGV fueling  stations  have been  completed  at two
Company  locations,  with both sites suited to refuel the Company and U.S.  Post
Office vehicles which utilize natural gas as fuel.

Peak Day Capability
The  Company's  gas  peak  day  capability  to meet its  1995-96  winter  season
requirements is summarized in the following portfolio:

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      Peak Day Capability                       Dth per day
      Firm Transportation Capacity                 248,486
      Storage                                      302,009
      Cogen Deliveries                              41,840
      Peak Shaving                                 124,700
                                                   -------
      Total                                        717,035
                                                   =======


Firm Transportation Capacity
The  Company has  contracted  for  306,486  Dth per day of  year-round  pipeline
transportation capacity, of which options to purchase 58,000 Dth per day for the
1995-1996 winter season have been sold. This year-round  transportation capacity
is provided  by four  interstate  pipeline  companies:  Transcontinental,  Texas
Eastern,  Tennessee Gas Pipeline Company and Iroquois Gas  Transmission  System.
The Company,  is a general partner in the Iroquois  pipeline  through its wholly
owned subsidiary, LILCO Energy Systems, Inc., with an equity share of 1%.

Storage
To assure  necessary  quantities to meet higher winter demand,  the Company also
has long-term firm storage  services which provide a total  operation  supply of
approximately  302,009 Dth per day, with a total  capacity of 24,203,885 Dth for
the winter period.  Of these totals,  291,789 Dth per day or a total capacity of
22,977,485 Dth is provided by gas storage fields in Pennsylvania  and 10,220 Dth
per day or a total  capacity of 1,226,400 Dth is provided by a gas storage field
in upstate  New York  operated by Honeoye  Storage  Corporation  (Honeoye).  The
Company currently owns 23-1/3% of the common stock of Honeoye.

In order to provide the Company  with  greater  security of supply and  enhanced
operational  flexibility  in meeting  peak-day  requirements,  the Company  also
contracts for storage capacity in Louisiana and Mississippi.  The Company has no
incremental  firm pipeline  transportation  capacity for these  supplies.  Up to
52,461 Dth per day can be  withdrawn  from the  Washington  storage  facility in
Louisiana which has a total storage  capacity of 4,459,220 Dth. Up to 18,300 Dth
per day can be withdrawn from the Eminence,  Mississippi storage facility and up
to 25,000 Dth per day can be withdrawn from the Hattiesburg, Mississippi storage
facility.   The  Eminence  and   Hattiesburg   facilities   have  total  storage
capabilities of 147,296 Dth and 250,000 Dth, respectively.

Cogen Deliveries
The  Company  has  contract  rights  with NYPA to receive a total of 900,000 Dth
during a  continuous  100-day  period  between  November  1 and March 31 of each
winter  season  at a daily  rate not to exceed  30,840  Dth per day.  Also,  the
Company has contract rights with  Nissequogue  Cogen facility to receive a total
of up to 330,000 Dth for 30 days  during each winter  season at a daily rate not
to exceed 11,000 Dth per day. In addition,  the Company has the right to request
812,500 Dth in

                                        9

<PAGE>



the winter  period from TBG Cogen  Facility  with the  obligation  to return the
actual taken quantities in kind during the following summer period.

Peak Shaving
The  Company  has its own peak  shaving  supplies  to meet its  requirements  on
excessively cold winter days. They include a liquefied  natural gas plant with a
storage capacity of approximately 600,000 Dth of gas and vaporization facilities
which  provide  103,300 Dth per day to the peakday  capability  of the Company's
system. In addition,  the Company has propane facilities that produce 21,400 Dth
per day of peak shaving with a storage capacity of approximately 100,000 Dth.

Firm Gas Supply
The Company has 212,069 Dth per day of firm  supplies,  of which  83,175 Dth per
day are Canadian and 128,894 Dth per day are domestic. Included in the long-term
firm Canadian gas is 2,525 Dth per day of gas contracted with Boundary Gas, Inc.
(Boundary). The Company owns 2.7% of the common stock of Boundary, a corporation
formed with 14 other gas utility  companies to act as a purchasing agent for the
importation of natural gas from Canada.  The Company also  purchases  91,223 Dth
per day in both the seasonal and monthly spot markets. In addition,  the Company
contracts for 3,194 Dth per day of winter seasonal supply on a month-to-month or
winter-term basis.

Gas Rates

A discussion of gas rates appears in Note 3 of Notes to Financial Statements for
the Year Ended December 31, 1995.

Other Activities

As a result of FERC Order  636,  pipeline  companies  can no longer act as sales
agents to "bundle" the mix of services from the  producers and other  interstate
pipeline companies.  This "unbundling" of gas transportation  activities and the
need for local  distribution  companies to negotiate  directly  with  producers,
other  suppliers and with  pipeline  companies has provided the Company with new
business  opportunities.  These  new  opportunities  include  providing  gas  to
non-traditional  markets,  including local distribution  companies and end-users
from  Mississippi to Connecticut.  In 1995 and 1994, total activity in this area
generated revenues of $24 million and $26 million,  respectively.  The Company's
firm gas customers  receive 85% and its  shareholders  receive 15% of the profit
realized from this activity.

Recovery of Transition Costs

Transition   costs  are  the  costs  associated  with  unbundling  the  pipeline
companies' merchant services in compliance with FERC Order No. 636. They include
pipeline companies'  unrecovered gas costs and the costs that pipelines incur as
a result of reforming or terminating their gas

                                       10

<PAGE>



supply contracts.  In order to recover transition costs, pipeline companies must
demonstrate to FERC that such costs were  attributable to Order No. 636 and that
they  were  prudently  incurred.  While  the  Company  has  challenged,  on both
eligibility and prudence  grounds,  its supplier  pipelines'  efforts to recover
their claimed  transition costs, the Company presently  estimates that its total
transition costs will be approximately $9 million.  As of December 31, 1995, the
Company  has paid  approximately  $7  million of these  transition  costs and is
currently collecting these costs from its gas customers in rates.

ENVIRONMENT:

General

The Company's  ordinary business  operations  necessarily  involve materials and
activities which subject the Company to federal, state and local laws, rules and
regulations dealing with the environment, including air, water and land quality.
These environmental requirements may entail significant expenditures for capital
improvements  or   modifications   and  may  expose  the  Company  to  potential
liabilities which, in certain instances,  may be imposed without regard to fault
or for  historical  activities  which  were  lawful at the time  they  occurred.
Enacted laws which may impose such  potential  liabilities  include (but are not
limited to) the federal Comprehensive  Environmental Response,  Compensation and
Liability  Act  of  1980  (commonly  known  as  Superfund),  the  federal  Toxic
Substances Control Act, the federal Clean Water Act (CWA), and the federal Clean
Air Act (CAA).

Air

Federal,  state  and  local  regulations  affecting  new and  existing  electric
generating  plants govern emissions  including sulfur dioxide (SO2) and nitrogen
oxide (NOx) and, potentially in the future, hazardous air pollutants.

Sulfur Dioxide Requirements
The laws  governing  the  sulfur  content  of the fuel oil  being  burned by the
Company  are  administered  by the New York State  Department  of  Environmental
Conservation (DEC) in compliance with the United States Environmental Protection
Agency (EPA). The Company does not expect to incur any costs to satisfy the 1990
amendments  to the federal CAA with respect to the  reduction of SO2  emissions,
since the  Company  already  uses oil with  acceptably  low levels of sulfur and
natural gas as boiler fuels.

Continuous  Emissions  Monitoring and NOx Requirements
During 1995, the Company spent  approximately $4.9 million in its ongoing effort
to comply with the 1990 amendments to the federal CAA. These  expenditures  were
necessary to meet continuous  emissions  monitoring (CEM) requirements,  Phase I
NOx reduction  requirements  and for upgrades to  particulate  control  systems.
Expenditures for CEMs in

                                       11

<PAGE>



1995 totaled $0.4 million. Expenditures for Phase I NOx and particulate controls
were $1.3  million.  In 1995,  the Company spent $3.2 million to upgrade its NOx
control systems. As a result of this earlier-than-required  upgrade, the Company
generated  NOx  reduction  credits which were sold for a price in excess of $3.2
million.

Subject to  requirements  that are  expected to be  promulgated  in  forthcoming
regulations,  the  Company  estimates  that  it  may be  required  to  spend  an
additional  $50 to $60  million  by the year 2003 to meet Phase II and Phase III
NOx reduction requirements under the federal CAA. In an effort to minimize costs
associated with anticipated NOx reduction  requirements,  the Company is engaged
in an  extensive  research and  development  project,  along with several  other
organizations  who have provided  co-funding,  to  demonstrate an innovative NOx
reduction technology at one of its power stations.  Through 1995,  approximately
$7 million have been expended by all of the co-funders, of which the Company has
contributed about $4.3 million.

Hazardous Air Pollutants
Utility boilers are presently exempt from regulation as sources of hazardous air
pollutants  until the EPA  completes  a study of the  risks,  if any,  to public
health  reasonably  anticipated  to occur as a result of  emissions  by electric
generating  units.  The EPA is expected to make a  determination  concerning the
need for control of hazardous air  pollutants  from utility  facilities in 1996.
Until such  determination is made by the EPA, the Company cannot fully determine
what,  if any,  costs  will  be  incurred  for  the  control  of  hazardous  air
pollutants.  The Company  currently  estimates  that it may be required to spend
approximately  $3.8 million by the year 2000 to meet the potential  requirements
for the control of hazardous air pollutants from its power plants.

Electromagnetic Fields
Electromagnetic  fields (EMF) occur  naturally  and also are  produced  wherever
there is  electricity.  These fields exist around power lines and other  utility
equipment. The Company is in compliance with all applicable regulatory standards
and   requirements   concerning  EMF.  The  Company  also  monitors   scientific
developments  in the study of EMF,  contributes to funding for research  efforts
and is actively  involved in customer and employee  outreach  programs to inform
the community of EMF  developments as they occur.  Although an extensive body of
scientific  literature  has not  shown  an  unsafe  exposure  level  or a causal
relationship  between EMF exposure and adverse health effects,  concern over the
potential  for  adverse  health  effects  will  likely  continue  without  final
resolution for some time.

To date,  the Company has not been  involved in any matter that  alleged  such a
causal  relationship.  However,  four residential property owners have initiated
separate  lawsuits  against the Company  alleging  that the existence of EMF has
diminished the value of their homes. These actions are in the preliminary stages
of discovery and their outcome

                                       12

<PAGE>



is  uncertain.  The Company is currently  unable to predict the impact,  if any,
that EMF-related matters will have on its financial position.

Water

In 1995,  the Company  spent $1.8  million to upgrade its waste water  treatment
facilities and for other measures  designed to protect  surface and ground water
quality.  The Company  plans to spend  approximately  $1.5 million for continued
enhancements in 1996.

Under the federal CWA and the New York State Environmental Conservation Law, the
Company is required to obtain a state  Pollutant  Discharge  Elimination  System
permit to discharge into the waters of the United States or New York State.  The
DEC has the  jurisdiction  to issue  these  permits and their  renewals  and has
issued  permits  for the  Company's  generating  units.  The  permits  allow the
continued use of the circulating  water systems which have been determined to be
in compliance with state Water Quality Standards. The permits also allow for the
continued use of the chemical treatment systems and for the continued  discharge
of water in accordance with applicable permit limits.

Long Island Sound Transmission Cables
The Connecticut  Department of  Environmental  Protection  (DEP) and the Company
have signed an Administrative Consent Order (ACO) which will require the Company
to address  leaks from an electric  transmission  cable  located  under the Long
Island Sound (Sound Cable).  The Sound Cable is jointly owned by the Company and
the Connecticut  Light and Power Company,  a subsidiary of Northeast  Utilities.
Specifically, the order requires the Company to evaluate existing procedures and
practices for cable maintenance, operations, fluid spill response procedures and
to propose alternatives to minimize fluid spill occurrences and their impacts on
the  environment.  Alternatives  to be evaluated  range from improving  existing
monitoring  and   maintenance   practices  to  removal  or  replacement  of  the
transmission  cables.  The Company is currently unable to determine the costs it
will  incur  to  complete  the  requirements  of the ACO or to  comply  with any
additional DEP requirements.

In addition,  the Company has been served a subpoena from the U.S.  Attorney for
the District of  Connecticut  to supply certain  written  information  regarding
releases of fluid from the Sound  Cable,  as well as  associated  operating  and
maintenance  practices  for  the  cable.  Since  the  investigation  is  in  its
preliminary  stages,  the Company is unable to  determine  the  likelihood  of a
criminal proceeding being initiated at this time. However,  the Company believes
all  activities  associated  with the response to releases  from the Sound Cable
were consistent with legal and regulatory requirements.

Land

Superfund imposes joint and several liability, regardless of fault,

                                       13

<PAGE>



upon generators of hazardous  substances for costs associated with environmental
cleanup  activities.   Superfund  also  imposes  liability  for  remediation  of
pollution caused by historical acts which were lawful at the time they occurred.

In the course of the  Company's  ordinary  business  operations,  the Company is
involved in the handling of materials that are deemed to be hazardous substances
under Superfund. These materials include asbestos, metals, certain flammable and
organic  compounds and dielectric fluids  containing  polychlorinated  biphenyls
(PCBs). Other hazardous substances may be handled in the Company's operations or
may be present at Company  locations as a result of historical  practices by the
Company or its predecessors in interest.

The Company has received  notice  concerning  possible claims under Superfund or
analogous  state laws  relating to a number of sites at which it is alleged that
hazardous substances generated by the Company and other potentially  responsible
parties (PRPs) were  deposited.  Estimates of the Company's  allocated  share of
costs for investigative,  removal,  and remedial activities at these sites range
from  preliminary  to  refined  and  are  updated  as  new  information  becomes
available.  The Company has notified its former and current  insurance  carriers
that it seeks to recover from them certain of these cleanup costs.  However, the
Company is unable to predict the amount of insurance  recovery,  if any, that it
may obtain.

Metal Bank Superfund Site
The EPA has  notified the Company that it is one of many PRPs that may be liable
for the  remediation  of a  licensed  disposal  site  located  in  Philadelphia,
Pennsylvania,  and operated by Metal Bank of America. The Company and nine other
PRPs,  all of which are public  utilities,  entered  into an ACO with the EPA to
conduct a Remedial  Investigation  and  Feasibility  Study (RI/FS).  Under a PRP
participation  agreement,  the  Company  is  responsible  for 8.2% of the  costs
associated  with this RI/FS,  which has been  completed  and is currently  being
reviewed by the EPA. The Company's total share of costs to date is approximately
$0.5 million.  The level of remediation required will be determined when the EPA
issues its decision,  but based on  information  available to date,  the Company
currently anticipates that the total cost to remediate this site will be between
$14  million and $30  million.  The  Company  has  recorded a liability  of $1.1
million  representing  its estimated  share of the additional  cost to remediate
this site.

PCB, Inc. Superfund Sites
The Company has also been named a PRP for disposal sites in Kansas City, Kansas,
and Kansas  City,  Missouri.  The two sites were used by a PCB,  Inc.  from 1982
until 1987 for the storage,  processing,  and  treatment of electric  equipment,
dielectric  oils,  and  materials  containing  PCBs.  According  to the EPA, the
buildings'  floor slabs and ceilings and the soil areas  outside the  buildings'
loading  docks  are  contaminated   with  PCBs.  The  Company  is  investigating
allegations that it had made agreements for disposal of PCBs or items containing
PCBs

                                       14

<PAGE>



at this site.

In 1994, the EPA requested  certain of the larger PRPs to form a group,  sign an
ACO,  and conduct a cleanup  program  for the sites  under the Toxic  Substances
Control  Act,  or, in the  alternative,  to perform a Superfund  cleanup for the
sites.  At the meeting,  the EPA provided the Company with documents  indicating
that the Company was  responsible  for less than 1% of the  materials  that were
shipped  to the  Missouri  site.  The EPA has not yet  completed  compiling  the
documents  for the Kansas  site.  The PRPs are  attempting  to organize  for the
purpose of  developing  and  implementing  acceptable  cleanup  programs for the
sites.  The Company is currently  unable to  determine  its share of the cost to
remediate  these  sites  or the  impact,  if  any,  on the  Company's  financial
position.

Port Washington Superfund Site
In 1989,  the EPA  notified the Company that it was a PRP for a landfill in Port
Washington,  New York.  The Company does not believe that it has  contributed to
the contamination of the site and has declined the EPA's requests to participate
in the investigation and remediation activities at the property. The Company has
not received further communications regarding this site.

Liberty Superfund Site
The EPA has notified the Company that it is a PRP in a Superfund site located in
Farmingdale,  New York.  Industrial  operations  took  place at this site for at
least fifty  years.  The PRP group has claimed  that the Company  should  absorb
expenses in the amount of  approximately  $0.1 million  associated with removing
PCB-contaminated  soils  from a portion  of the site  which  formerly  contained
electric transformers. The Company is currently unable to determine its share of
the cost of  remediation  or the  impact,  if any,  on the  Company's  financial
position.

Manufactured Gas Plant Sites
The DEC has  required  the  Company  and  other  New  York  State  utilities  to
investigate and, where necessary,  remediate their former manufactured gas plant
(MGP)  sites.  Currently,  the Company is the owner of six pieces of property on
which the Company or certain of its predecessor  companies produced manufactured
gas. The Company expects to enter into an ACO with the DEC in 1996 regarding the
management of  environmental  activities at these six  properties.  Although the
exact amount of the Company's  cleanup costs cannot yet be determined,  based on
the findings of investigations at two of these six sites,  preliminary estimates
indicate  that it may cost  approximately  $35  million to clean up all of these
sites through the year 2005 and

                                       15

<PAGE>



accordingly,  the Company  has  recorded a $35  million  liability.  The Company
believes  that the PSC will  provide for future  recovery of these costs and has
recorded a $35 million  regulatory  asset.  The Company is also  evaluating  its
responsibilities  with respect to several other former MGP sites that existed in
its territory which it does not presently own. Research is underway to determine
the existence and nature of operations and relationship,  if any, to the Company
or its predecessor companies.  Operations at these facilities in the late 1800's
and early  1900's may have  resulted in the disposal of certain  waste  products
located on these sites.

Inwood Gas Holder Property
The  Company  entered  into an ACO with the DEC to  remediate  lead-contaminated
soils at a  former  distribution  gas  holder  site in  Inwood,  New  York  that
contained  a gas holder  coated with lead  paint.  Based on the current  cleanup
objectives, 1996 remediation costs are estimated at about $1 million.

North Hills Leak
The Company has undertaken remediation of certain soil locations in North Hills,
New York that were impacted by a release of insulating  fluid from an electrical
cable in August 1994. The need for any further remediation has not, as yet, been
finalized. If additional remediation is required,  preliminary estimated cleanup
costs  expected to be incurred could range from $0.2 to $5 million over the next
four years.  The Company has initiated cost recovery  actions  against the third
parties it believes are  responsible  for causing the cable leak, the outcome of
which is uncertain.

Storage Facilities
As a result of petroleum  leaks from  underground  storage  facilities and other
historical  occurrences,  the Company is required to investigate and, in certain
cases,  remediate affected soil and groundwater conditions at several facilities
within its service territory. The aggregate costs of such remediation work could
be between $3 and $5 million and are not  expected to have a material  impact on
the Company's financial position.

The  Company  believes  that all  significant  costs  incurred  with  respect to
environmental  investigation  and  remediation  activities  will be  recoverable
through rates.

Nuclear Waste

Under the federal Low Level  Radioactive Waste Policy Amendment Act of 1985, New
York State was  required,  by January 1, 1993, to have arranged for the disposal
of all low  level,  radioactive  waste  generated  within  the  state or, in the
alternative,  contracted  for the  disposal  of waste at an  operating  facility
outside the state. As a result,  New York has stated its intentions of arranging
for an  in-state  disposal  facility  due  to  the  large  volume  of low  level
radioactive waste it generated within the state, and has committed to

                                       16

<PAGE>



develop a plan for the  management of such waste during the interim period until
a disposal facility is available.  New York State is still developing a disposal
methodology and acceptance criteria for a disposal facility. The latest New York
State low level  radioactive  waste site  development  schedule  now assumes two
possible siting scenarios,  a volunteer  approach and a non-volunteer  approach,
either of which would begin operation in 2001.  South Carolina has permitted low
level radioactive waste generators outside the state, including New York, access
to its waste disposal facility,  effective July 1995.  Previously,  New York was
denied access to the South Carolina waste disposal facility since the expiration
of its contract in June 1994.

NMPC has implemented a low level radioactive waste management  program that will
properly handle interim on-site storage of low level  radioactive waste for NMP2
for at least  ten  years.  The  Company's  share of the  costs  associated  with
temporary storage and ultimate disposal are expected to be recovered in rates.

In addition,  NMPC, on behalf of the NMP2 cotenants, has entered into a contract
with the DOE for the permanent  storage of NMP2 spent nuclear fuel.  The Company
reimburses  NMPC for its 18% share of the cost under the  contract  at a rate of
$1.00  per  megawatt  hour  of net  generation  less a  factor  to  account  for
transmission line losses. The Company is collecting its portion of this fee from
the  Company's  electric  ratepayers.  Progress in  developing  a permanent  DOE
repository  for such high  level  radioactive  material  has been slow and it is
anticipated  that the DOE facility  will not be  available to accept  deliveries
until at least 2010.  NMPC does not  anticipate  that the DOE will accept all of
its spent fuel immediately upon the opening of its facility,  but rather expects
a  transfer  period  that  will  extend  to the  year  2044.  NMPC  has  several
alternatives under  consideration to provide additional storage  facilities,  as
necessary.  Each alternative will likely require NRC approval, may require other
regulatory  approvals  and would  likely  require  incurring  additional  costs.
Currently,  all spent  nuclear  fuel from NMP2 is being stored at the NMPC site.
The  Company  does not  anticipate  that the  possible  unavailability  of a DOE
facility until 2010 will inhibit the operation of NMP2.

For  information  concerning  environmental   litigation,   see  Item  3  -Legal
Proceedings--Environmental.

THE COMPANY'S SECURITIES:

General

The Company's securities are rated by Moody's Investors Service,  Inc., Standard
and Poor's Ratings Group,  Fitch  Investors  Service,  Inc. and Duff and Phelps,
Inc. For information  relating to the ratings of the Company's  securities,  see
Item 7 "Management's Discussion and Analysis


                                       17

<PAGE>



of Financial Condition and Results of Operations" for the Year Ended
December 31, 1995.

The First Mortgage

With the early  redemption of all outstanding  First Mortgage Bonds in September
1995, the Company  satisfied its obligation and discharged the lien of the First
Mortgage.  When the First  Mortgage was  discharged,  the Company's  outstanding
General and Refunding Bonds (the G&R Bonds) became its only outstanding  secured
indebtedness.

The G&R Mortgage

The  Company's  General  and  Refunding  Indenture  dated  June 1, 1975 (the G&R
Indenture or G&R  Mortgage) is a lien upon  substantially  all of the  Company's
properties.  Outstanding at December 31, 1995 were  approximately  $2 billion of
G&R Bonds.  Additional  information  concerning  the  Company's  G&R Mortgage is
discussed below and in Note 7 of Notes to the Financial  Statements for the Year
Ended December 31, 1995.

Under the G&R  Mortgage,  the Company may issue G&R Bonds on the basis of either
matured or redeemed G&R Bonds or on the basis of the Bondable  Value of Property
Additions (BVPA).  Generally, when issuing G&R Bonds, the Company must satisfy a
mortgage  interest  coverage  requirement,  known as the G&R  Mortgage  Interest
Coverage.  The G&R Mortgage  Interest Coverage requires that the net earnings as
defined in the G&R  indenture,  available  for interest  for any 12  consecutive
calendar months within the 15 consecutive calendar months preceding the issuance
of any G&R Bonds must be equal to at least two times the stated annual  interest
payable on  outstanding  G&R Bonds,  including any new G&R Bonds.  Under the G&R
Mortgage  Interest  Coverage,  the  Company  would  currently  be able to  issue
approximately  $4.9 billion of additional  G&R Bonds based upon net earnings for
the 12 months  ended  December 31, 1995 and an assumed  interest  rate of 9% for
such additional G&R Bonds. A change of 1/8 of 1% in the assumed interest rate of
such G&R Bonds  would  result in a change of  approximately  $67  million in the
amount of such G&R Bonds that the Company  could  issue.  The maximum  amount of
additional  G&R Bonds which the Company is currently  able to issue on the basis
of  either  matured  or  retired  G&R  Bonds  and on the  basis  of the  BVPA is
approximately $627 million.

Under the provisions of the G&R indenture, the Company must also satisfy by June
30 of each year a Sinking Fund requirement  which is equal to 1% of the total of
all G&R Bonds  outstanding  on December 31 of the prior year.  The Sinking  Fund
requirement  can be satisfied by  depositing  cash with the Trustee which can be
withdrawn  later by  substituting  60% of BVPA or  retired  G&R Bonds  when they
become available, or an amount not exceeding 60% of BVPA or the principal amount
of retired G&R Bonds. The Company believes that, based upon currently  scheduled
redemptions  and maturities,  it will have sufficient  retired G&R Bonds for the
foreseeable future to satisfy the

                                       18

<PAGE>



requirements of the G&R Sinking Fund.  Based upon this  calculation for the year
ended December 31, 1995, the Sinking Fund  requirement is $25 million which will
be  satisfied  by June 30,  1996.  The  Company  is  planning  to  satisfy  this
requirement in 1996 with retired G&R Bonds, property additions or cash.

The G&R Mortgage also has a Maintenance  Fund covenant  which  requires that the
aggregate  amount of property  additions  added  subsequent to December 31, 1974
must be, as of the end of each calendar year  subsequent to 1974, at least equal
to the cumulative  provision for  depreciation  (as defined in the G&R Mortgage)
from December 31, 1974. The G&R Mortgage requires cash (or retired G&R Bonds) to
be  deposited  to  satisfy  the  Maintenance  Fund  requirement  only  when such
cumulative  provision for depreciation exceeds such aggregate amount of property
additions.  As of December  31,  1995,  the amount of such  cumulative  property
additions  calculated  pursuant  to the G&R  Mortgage  was  approximately  $10.0
billion, including approximately $5.5 billion of property additions attributable
to  Shoreham.  Also,  as of  December  31,  1995,  the amount of the  cumulative
provision  for  depreciation,   similarly  calculated,  was  approximately  $1.7
billion. The Company anticipates that the aggregate amount of property additions
will continue to exceed the cumulative provision for depreciation.

Unsecured Debt

The Company's G&R Mortgage and its Restated  Certificate of Incorporation do not
contain any  limitations  upon the issuance of  unsecured  debt.  The  Company's
unsecured debt consists of Debentures and certain tax-exempt securities.

The  Company's   Debenture   Indenture,   dated  as  of  November  1,  1986,  as
supplemented,  and its  Debenture  Indenture,  dated as of November 1, 1992,  as
supplemented, (together, the Debenture Indentures) each provide for the issuance
of an  unlimited  amount  of  Debentures  to be issued  in  amounts  that may be
authorized from time to time in one or more series. The Debentures are unsecured
and rank  pari  passu  with all  other  unsecured  indebtedness  of the  Company
subordinate  to the  obligations  secured  by the  Company's  G&R  Mortgage.  At
December  31,  1995,  there  were   approximately  $2.3  billion  of  Debentures
outstanding.

As of December 31, 1995, the Company had outstanding  approximately $917 million
principal  amount of promissory  notes,  securing:  (i) $2 million of tax-exempt
Industrial Development Revenue Bonds (IDRBs); (ii) approximately $215 million of
tax-exempt  Pollution  Control Revenue Bonds (PCRBs);  and (iii) $700 million of
tax-exempt  Electric Facility Revenue Bonds (EFRBs).  Of these amounts,  certain
series are subject to periodic tenders.

For additional information respecting tender provisions and other information on
the  Company's  outstanding  debt  securities  see Note 7 of Notes to  Financial
Statements for the Year Ended December 31, 1995.


                                       19

<PAGE>



Equity Securities

Preferred Stock
The Company's  Restated  Certificate of Incorporation  provides that the Company
may not issue additional  preferred stock unless for any 12 consecutive calendar
months within the 15 calendar  months  immediately  preceding the calendar month
within which such  additional  shares  shall be issued,  the net earnings of the
Company  available  for  the  payment  of  interest  charges  on  the  Company's
interest-bearing  indebtedness,  determined after provision for depreciation and
all taxes, and in accordance with sound accounting practice,  shall have been at
least one and one-half times the aggregate of the annual interest charges on the
interest-bearing indebtedness of the Company and annual dividend requirements on
all shares of preferred stock to be outstanding  immediately  after the proposed
issue of such shares of the preferred  stock (the Earnings  Ratio).  The Company
currently  satisfies the Earnings Ratio and could issue up to approximately $450
million of preferred  stock.  When the proceeds  from the sale of the  preferred
stock  to be  issued  are  used  to  redeem  outstanding  preferred  stock,  the
requirement  to satisfy the Earnings  Ratio is not  applicable,  if the dividend
requirement and the  requirements  for redemption in a voluntary  liquidation of
the preferred  stock to be issued do not exceed the  respective  amounts for the
preferred stock which is to be retired.  Additional  preferred stock may also be
issued beyond amounts permitted under the Earnings Ratio with the approval of at
least  two-thirds  of the votes  entitled to be cast by the holders of the total
number of shares of outstanding preferred stock.

Default in the  payment of  dividends  on any  shares of  preferred  stock in an
amount  equivalent to or exceeding four full quarterly  dividends for any series
of preferred  stock  entitles all holders of shares of preferred  stock,  voting
separately as a class and regardless of series, to elect a majority of the Board
of Directors of the Company.  The remaining Directors are elected by the holders
of common  stock.  The right of holders of shares of preferred  stock to elect a
majority of the Board of Directors  ceases when and if the Company  ceases to be
in default in the payment of its preferred  stock  dividends.  At that time, the
terms of office of the  Directors  of the  Company  elected  by the  holders  of
preferred  stock  terminate and the resulting  vacancies are to be filled by the
vote of the remaining common stock Directors.

Preference Stock
Issuance of preference  stock,  which is subordinate to the Company's  preferred
stock,  but senior to its common stock,  with respect to declaration and payment
of dividends and the right to receive amounts payable on any  dissolution,  does
not  require  satisfaction  of  a  net  earnings  test  or  any  other  coverage
requirement, unless established by the Board of Directors for one or more series
of preference  stock,  prior to the issuance of such series. No preference stock
has been issued by the  Company,  nor does the Company  currently  plan to issue
any.


                                       20

<PAGE>



Common Stock
The  Company's  common  stock  is  listed  on the New  York  and  Pacific  Stock
Exchanges, and is traded under the symbol "LIL". The Board of Directors' current
policy  is to pay cash  dividends  on the  common  stock on a  quarterly  basis.
However,  before  declaring  any  dividends,  the  Company's  Board of Directors
considers,  among other factors, the Company's financial condition,  its ability
to comply with provisions of the Company's Restated Certificate of Incorporation
and the availability of retained earnings, future earnings and cash.

EXECUTIVE OFFICERS OF THE COMPANY:

Current  information  regarding the Company's  Executive  Officers,  all of whom
serve at the will of the Board of Directors, follows:

William J. Catacosinos:  Dr.  Catacosinos has served as Chairman of the Board of
Directors and Chief Executive  Officer of the Company since January 1984, and as
a Director since December 1978. He currently  chairs the Executive  Committee of
the Company's Board of Directors.  Dr.  Catacosinos  also served as President of
the Company from March 1984 to January 1987 and from March 1994 to present.  Dr.
Catacosinos,  65, a resident  of Mill Neck,  Long  Island,  earned a bachelor of
science  degree,  a masters  degree in  business  administration  and a doctoral
degree in economics from New York University. Dr. Catacosinos is a member of the
Boards of First National Bank of L.I.,  U.S. Life  Corporation,  the Long Island
Association,  the  Business  Alliance  for a New New  York,  and a member of the
Advisory  Committee of the Huntington  Township  Chamber  Foundation.  He is the
former  Chairman and Chief  Executive  Officer of Applied  Digital Data Systems,
Inc.,  Hauppauge,  New York;  served as Chairman of the Board and  Treasurer  of
Corometric Systems,  Inc. of Wallingford,  Connecticut;  and served as Assistant
Director at Brookhaven National Laboratory,  Upton, New York. Dr. Catacosinos is
a former member of the Boards of Utilities  Mutual  Insurance  Company;  Ketema,
Inc.; Austin  International  Communications;  and the German American Chamber of
Commerce.

Theodore A. Babcock:  Treasurer  since February  1994,  and Assistant  Corporate
Secretary  since January 1996,  Mr.  Babcock  joined the Company in July 1992 as
Assistant Treasurer. He previously spent five years in the AMBASE Corporation as
an  Assistant  Vice  President  and was promoted in 1988 to Vice  President  and
Treasurer.  Prior to AMBASE,  Mr. Babcock spent 11 years with the Associated Dry
Goods Corporation  where he was promoted to Assistant  Treasurer and Director of
Corporate Treasury  Operations in 1984. Mr. Babcock,  41, received a bachelor of
science  degree in accounting  from  Manhattan  College and a masters  degree in
finance from Iona College.

James T. Flynn:  Chief  Operating  Officer since March 1994 and  Executive  Vice
President since April 1992, Mr. Flynn joined the Company in October 1986 as Vice
President  of Fossil  Production.  He later  assumed the  position of Group Vice
President,  Engineering and Operations.  Before joining the Company,  Mr. Flynn,
62, was General

                                       21

<PAGE>



Manager-Eastern  Service Department for General Electric.  His career began as a
member of General  Electric's  Technical  Marketing  Program in 1957. He holds a
bachelor of science degree in mechanical  engineering  from Bucknell  University
and is a Licensed Professional Engineer in the State of Pennsylvania.

Joseph E. Fontana:  Controller of the Company  since October 1994,  Mr.  Fontana
joined the Company in December 1992 as Director of Accounting Services.  He held
the position of Assistant  Controller from February 1994 through September 1994.
In his  capacity  as  Controller,  Mr.  Fontana  serves as the Chief  Accounting
Officer.  Mr. Fontana is a member of the American  Institute of Certified Public
Accountants  and the New York State  Society of  Certified  Public  Accountants.
Before   joining  the  Company,   Mr.  Fontana  was  a  Senior  Manager  at  the
international  accounting  firm,  Ernst & Young LLP.  Mr.  Fontana,  38, holds a
bachelor of science degree in accounting from Westchester State College and is a
Certified Public Accountant.

Robert X.  Kelleher:  Vice  President of Human  Resources  since July 1986,  Mr.
Kelleher joined the Company in 1959 and has held various managerial positions in
the   Finance,   Accounting,   Purchasing,   Stores   and   Employee   Relations
organizations. He was Industrial Relations Manager from 1975 to 1979, Manager of
the Employee Relations Department from 1979 to 1985 and Assistant Vice President
of the Employee Relations  Department from 1985 to 1986. Mr. Kelleher,  59, is a
graduate of St. Francis College and the Human Resources Management and Executive
Management  Programs of Pennsylvania State University.  Mr. Kelleher is a member
of  the  American   Compensation   Association,   Personnel  Directors  Council,
Industrial  Relations Research Institute,  and Edison Electric Institute's Labor
Relations Committee.

John D. Leonard, Jr.: Vice President of Engineering and Construction since April
1994,  Mr.  Leonard  joined  the  Company in 1984 as Vice  President  of Nuclear
Operations.  He continues to be  responsible  for nuclear  issues.  Mr.  Leonard
assumed additional duties as Vice President of Corporate Services from July 1989
through March 1994.  Mr.  Leonard was the Vice  President  and  Assistant  Chief
Engineer for Design and Analysis at the New York Power  Authority,  from 1980 to
1984. Prior to this position, he served as a Resident Manager of the Fitzpatrick
Nuclear Power Plant for approximately five years. Before accepting a position at
the New York Power  Authority,  Mr.  Leonard  served as Corporate  Supervisor of
Operational  Quality  Assurance of the Virginia Electric Power Company from 1974
to 1976. In 1974, Mr. Leonard retired with the rank of Commander from the United
States Navy,  having commanded two  nuclear-powered  submarines in a career that
spanned 20 years. He holds a bachelor of science degree from Duke University and
a master of science degree from the Naval Post Graduate  School.  He is 63 and a
Licensed Professional Engineer in the State of New York.

Adam M. Madsen: Vice President of Corporate & Strategic Planning since 1984, Mr.
Madsen, 59, holds a bachelors degree in electrical

                                       22

<PAGE>



engineering  from  Manhattan  College and a master of science  degree in nuclear
engineering  from Long Island  University.  He has been with the  Company  since
1961, serving in various engineering  positions including Manager of Engineering
from 1978 to 1984.  Prior to that time,  he held the  position of Manager of the
Planning   Department.   Since  1978,   Mr.   Madsen  has  been  the   Company's
representative  to the Planning  Committee  of the New York Power Pool.  He is a
member of the Northeast Power Coordinating Council's Executive Committee and the
Council's  Reliability  Coordinating  Committee.  He also serves on the Board of
Directors of the Empire State Electric Energy Research Company.  Mr. Madsen is a
Licensed Professional Engineer in the State of New York.

Kathleen A. Marion:  Vice  President of Corporate  Services since April 1994 and
Corporate  Secretary since April 1992, Ms. Marion has served as Assistant to the
Chairman since April 1987. She was Assistant Corporate Secretary from April 1990
to 1992.  Ms.  Marion,  41, has a bachelor  of science  degree in  business  and
finance from the State University of New York at Old Westbury.

Arthur C.  Marquardt:  Senior Vice  President of Gas  Business  Unit since March
1992, Mr.  Marquardt joined the Company in January 1991. He held the position of
Vice  President of Strategic  Business  Planning from January 1991 through March
1992. He is Chairman of the New York Facilities Executive Committee,  a Director
of the Huntington Chamber of Commerce, the Huntington Chamber Foundation and the
Long  Island  Builders  Institute,  and a member of the  Family  Service  League
Business Advisory Council.  He has had extensive and varied business  experience
at Combustion  Engineering Inc.; General Electric Company;  Quadrex Corporation;
and Pacific  Nuclear  Systems,  Inc. where he was President and Chief  Operating
Officer. Mr. Marquardt,  49, received a bachelor of science degree in mechanical
engineering from Tufts University.

Brian R.  McCaffrey:  Vice  President of  Administration  since March 1987,  Mr.
McCaffrey  joined the Company in 1973.  Mr.  McCaffrey,  51, holds a bachelor of
science  degree in aerospace  engineering  from the University of Notre Dame. He
also  received  a  master  of  science  degree  in  aerospace  engineering  from
Pennsylvania  State  University  and a  master  of  science  degree  in  nuclear
engineering from Polytechnic University.  He is a Licensed Professional Engineer
in the  State of New  York.  Prior to this  assignment  as Vice  President,  Mr.
McCaffrey  served in many positions in the nuclear  organizations of the Company
and positions in engineering  capacities  associated with gas turbine and fossil
power station projects.  Mr. McCaffrey is a member of the Executive Board of the
Suffolk County Council Boy Scouts of America.

Joseph W.  McDonnell:  Vice  President of External  Affairs since July 1992, Dr.
McDonnell,  joined the  Company in 1984.  Dr.  McDonnell  was  Assistant  to the
Chairman   from  1984  through  1988  when  he  was  named  Vice   President  of
Communications.  Prior to joining the Company,  he was the Director of Strategic
Planning and Business  Administration for Applied Digital Data Systems, Inc. and
Associate  Director of the  University  Hospital at the State  University of New
York at Stony

                                       23

<PAGE>



Brook. Dr.  McDonnell,  44, holds bachelor of arts and master of arts degrees in
philosophy  from the State  University  of New York at Stony Brook and a Ph.D in
communications from the University of Southern California.

Leonard P.  Novello:  Mr.  Novello  joined the  Company in April 1995 as General
Counsel.  Before  joining the Company,  Mr.  Novello was General  Counsel at the
international  accounting  firm of KPMG Peat Marwick.  As General  Counsel,  Mr.
Novello  advised  senior  management  on a variety of  litigation  and corporate
issues  and was  responsible  for all legal  matters  arising  out of the firm's
operations and its audit, tax and management  consulting  engagements.  Prior to
joining Peat Marwick in 1975 as an Associate  General  Counsel,  Mr. Novello was
associated with the New York law firm of Cravath,  Swaine and Moore. Mr. Novello
is  active  in  professional  associations  and is a  member  of  the  Executive
Committee of the Litigation Commercial and Federal Section of the New York State
Bar Association,  a member of the Professional  Responsibility  Committee of the
Association  of the Bar of the City of New York and is a  Vice-President  of the
Federal Bar Council.  He is also a member of the Executive  Committee of the CPR
Institute for Dispute Resolution.  Mr. Novello, 55, has a bachelor's degree from
the College of the Holy Cross and a juris doctorate from Fordham University.

Anthony Nozzolillo: Senior Vice President of Finance and Chief Financial Officer
of the Company  since  February  1994,  Mr.  Nozzolillo  served as the Company's
Treasurer  from July 1992 to February  1994.  He has been with the Company since
1972 serving in various positions  including  Manager of Financial  Planning and
Manager of Systems Planning.  Mr. Nozzolillo is a former member of the Boards of
Utilities  Mutual Insurance  Company.  Mr.  Nozzolillo,  47, holds a bachelor of
science  degree in  electrical  engineering  from the  Polytechnic  Institute of
Brooklyn  and a master  of  business  administration  degree  from  Long  Island
University C.W. Post Campus.

Richard  Reichler:  Deputy  General  Counsel  and Vice  President  of  Financial
Planning and Taxation since  December  1994,  Mr.  Reichler held the position of
Assistant Vice President for Tax and Benefits Planning from October 1992 through
December  1994.  Prior  to  joining  the  Company,  he  was  a  partner  in  the
international  accounting firm of Ernst & Young LLP for twenty-three  years. Mr.
Reichler,  61,  holds a bachelor  of arts  degree  from  Columbia  College and a
bachelor of law degree from Columbia  University  School of Law.  Since 1989, he
has  taught  various  courses  at  Baruch  College,  including  state  and local
taxation,  corporate taxation and real estate taxation.  He has authored several
publications  on tax and employee  benefit  topics and has served as a member of
the Executive Committee of the Tax Section of the New York State Bar Association
and as an Advisor to the Urban Development  Corporation High Technology Advisory
Council.

William G. Schiffmacher:  Vice President of Customer Relations since April 1994,
Mr. Schiffmacher held the position of Vice President of

                                       24

<PAGE>



Electric  Operations from July 1990 through March 1994. He joined the Company in
1965 after receiving a bachelor of electrical  engineering degree from Manhattan
College.  Mr.  Schiffmacher,  52,  also  holds a master  of  science  degree  in
management  engineering  from Long Island  University.  He has held a variety of
positions  in the  Company,  including  Manager of Electric  System  Operations,
Manager  of  Electrical  Engineering  and  Vice  President  of  Engineering  and
Construction.

Robert B. Steger:  Vice President of Electric  Operations  since April 1994, Mr.
Steger held the position of Vice  President of Fossil  Production  from February
1990  through  March  1994.  He joined  the  Company  in 1963 and has since held
progressive  operating and engineering  positions  including Manager of Electric
Production-Fossil  from 1985 through 1989. Mr.  Steger,  59, holds a bachelor of
mechanical   engineering   degree  from  Pratt   Institute  and  is  a  Licensed
Professional Engineer in the State of New York.

William E. Steiger,  Jr.: Vice President of Fossil  Production since April 1994,
Mr.  Steiger,  52,  held the  position  of Vice  President  of  Engineering  and
Construction  from July 1990  through  March 1994.  He has been with the Company
since 1968.  During his career  with the  Company,  he has  served,  among other
positions, as Lead Nuclear Engineer for Shoreham,  Chief Operations Engineer for
Shoreham,  Plant  Manager for  Shoreham as well as Assistant  Vice  President of
Nuclear Operations. Mr. Steiger, received a bachelor of science degree in marine
engineering  from the United  States  Merchant  Marine  Academy  and a master of
science degree in nuclear engineering from Long Island University.

Edward J. Youngling:  Senior Vice President of the Electric  Business Unit since
April  1994,  Mr.  Youngling  held the  position of Vice  President  of Customer
Relations  and  Conservation  from March 1993 through  March 1994. He joined the
Company in 1968 as an Assistant Engineer in the electric  production  department
and has held various positions in the offices of fossil production,  engineering
and  nuclear  operations  including  service  as  Department  Manager of Nuclear
Engineering. In 1988, Mr. Youngling was named Vice President of Conservation and
Load  Management.  In 1990,  Mr.  Youngling  became Vice  President  of Customer
Relations.  The Office of Customer Relations and the Office of Conservation were
merged in March 1994. Mr.  Youngling,  51, holds a bachelor of science degree in
mechanical engineering from Lehigh University.

                                       25

<PAGE>



CAPITAL REQUIREMENTS, LIQUIDITY AND CAPITAL PROVIDED:

Information as to "Capital  Requirements",  "Liquidity"  and "Capital  Provided"
appears in Item 7, "Management's  Discussion and Analysis of Financial Condition
and Results of Operations" under the heading Liquidity and Capital  Requirements
and Capital Provided for the Year Ended December 31, 1995.


ITEM 2.       PROPERTIES

The location and general  character of the  principal  properties of the Company
are described in Item 1, "Business" under the headings "Electric Operations" and
"Gas Operations."

ITEM 3.       LEGAL PROCEEDINGS

Shoreham

Pursuant to the LIPA Act,  LIPA is  required  to make  payments-in-lieu-of-taxes
(PILOTs) to the  municipalities  that impose real  property  taxes on  Shoreham.
Pursuant to the 1989 Settlement, the Company agreed to fund LIPA's obligation to
make Shoreham  PILOTs.  The timing and duration of PILOTs under the LIPA Act are
the subject of litigation entitled LIPA, et al. v. Shoreham-Wading River Central
School District, et al., brought in Nassau County Supreme Court by LIPA against,
among others,  Suffolk  County,  the Town of Brookhaven and the  Shoreham-Wading
River  Central  School  District.  The Company was permitted to intervene in the
lawsuit.  On January  10,  1994,  the  Appellate  Division,  Second  Department,
affirmed a lower court's March 29, 1993 decision  holding,  in major part,  that
the Company is not  obligated  for any real  property  taxes that accrued  after
February  28,  1992,  attributable  to property  that it conveyed to LIPA,  that
PILOTs  commenced on March 1, 1992,  that PILOTs are subject to refunds and that
the LIPA Act does not provide for the  termination of PILOTs.  Generally,  these
holdings are  favorable to the Company.  In October  1995,  the Court of Appeals
granted  the  parties'  motion  for leave to appeal  the  lower  court  decision
following an agreement  between the parties to voluntarily  dismiss  outstanding
causes of action.  The proper  amount of PILOTs is to be  determined  in pending
litigation described immediately below.

The costs of Shoreham included real property taxes imposed by, among others, the
Town  of  Brookhaven  on  Shoreham  and   capitalized   by  the  Company  during
construction.  The Company had sought judicial review in New York Supreme Court,
Suffolk  County  (Long  Island  Lighting  Company v. The Assessor of the Town of
Brookhaven, et al.) of the assessments upon which those taxes were based for the
years 1976 through 1992 (excluding  1979).  The Supreme Court  consolidated  the
review of the tax years at issue into two phases:  1976 through 1983,  excluding
1979,  which had been  settled  (Phase I); and 1984  through 1992 (Phase II). In
October 1992, the Supreme Court ruled that

                                       26

<PAGE>



Shoreham had been  overvalued for real property tax purposes for Phase I. In May
1995, the New York Court of Appeals denied the request of the Town of Brookhaven
and  other  respondents  for  leave to  appeal  this  decision,  which  had been
previously  affirmed in an  unanimous  decision by the New York State  Appellate
Division,  Second Department.  Thereafter, in January 1996, the Company received
approximately $81 million,  including interest,  from Suffolk County pursuant to
this Phase I judgment.

In the Phase II proceeding, the Company is seeking to recover over $500 million,
plus interest,  in property taxes paid on Shoreham for the years  1984-1992.  In
this proceeding, the taking of evidence has been completed and final briefs have
been filed by the parties. The amount of the Company's recovery,  if any, in the
Phase II proceeding and the timing of all refunds cannot yet be determined. LIPA
has been permitted to intervene in the proceeding for the 1991-92 tax year which
under the Appellate Division's decision in LIPA, et al. v. Shoreham-Wading River
Central School  District,  et al.,  discussed  above,  will partially  establish
LIPA's PILOT obligation.  Pursuant to the Appellate Division's decision,  LIPA's
PILOT  obligations  will be  determined  either by  agreement  or in a  separate
proceeding challenging the Shoreham assessment for the 1992-93 tax year.

Environmental

On February 18, 1994, a lawsuit was filed in the United  States  District  Court
for the  Eastern  District  of New York by the Town of  Oyster  Bay (the  Town),
against the Company and 19 other PRPs. The Town is seeking  indemnification  for
remediation  and  investigation  costs that have been or will be incurred  for a
federal  Superfund site in Syosset,  New York,  which served as a Town-owned and
operated  landfill  between  1954 and 1975.  In a Record of  Decision  issued in
September  1990, the EPA set forth a remedial design plan, the cost of which was
estimated  at  $27  million  and  is  reflected  in the  Town's  lawsuit.  In an
Administrative  Consent  Decree  entered  into  between  the EPA and the Town in
December 1990, the Town agreed to undertake remediation at the site. The Company
is  participating  in a joint PRP defense effort with several other  defendants.
Liability,  if imposed,  would be joint and  several.  While the outcome of this
matter is not  certain,  based upon the  Company's  past  experience  in similar
matters and the number and financial condition of the corporate defendants named
in the litigation, the Company does not believe that this proceeding will have a
material adverse effect on its financial condition.

Human Resources

Pending  before  federal  and  state  courts,   the  federal  Equal   Employment
Opportunity  Commission  and the New York  State  Division  of Human  Rights are
charges by individuals alleging that the Company  discriminated against them, or
that they were the subject of harassment, on various grounds.

                                       27

<PAGE>




The Civil Rights Bureau of the New York Attorney General's office has subpoenaed
the Company for the  production of documents to aid in its  investigation  as to
whether the Company has engaged in  discriminatory  employment  practices  based
upon age. No charges have been filed and the  Attorney  General has not made any
further inquiry.

The Company has  estimated  that any costs to the Company  resulting  from these
matters will not have a material adverse effect on its financial condition.

In May 1995, eight  participants of the Company's  Retirement  Income Plan (RIP)
filed a lawsuit  against the Company,  the RIP and Robert X. Kelleher,  the Plan
Administrator,  in the United States District Court for the Eastern  District of
New York (Becher,  et al. v. Long Island Lighting  Company,  et al.). In January
1996,  the Court ordered that this action be maintained as a class action.  This
proceeding  arose in connection with the plaintiffs'  withdrawal,  approximately
twenty-five years ago, of contributions made to the Plan, thereby resulting in a
reduction of their pension benefits. The plaintiffs are now seeking, among other
things, to have these reduced benefits  restored to their pension accounts.  The
Company's  liability,  if any,  resulting  from this  proceeding  cannot  yet be
determined.  However,  the Company  maintains  that the  plaintiffs'  claims are
without merit and intends to vigorously defend such claims.

Other Matters

On January 13, 1993,  the New York State  Department  of Law (DOL)  informed the
Company that the DOL's Antitrust  Bureau opened an  investigation  into its Full
Service Pilot Program and Contractor Advisory Council,  two programs designed to
increase the Company's  residential  natural gas sales.  The DOL stated that the
implementation  of the Full  Service  Pilot  Program  and the  practices  of the
Contractor  Advisory Council may have  anticompetitive  effects in the gas-fired
heating  equipment  installation and conversion  business and that a preliminary
investigation  has  raised  questions  of  possible  violations  of the New York
General  Business  Law and the  Sherman  Act.  The DOL has not taken any further
action in this matter. If required,  the Company expects that it can demonstrate
that the programs  identified by the DOL for  investigation  are very limited in
scope and do not involve any violations. The outcome of the investigation by the
DOL, if adverse,  is not  expected  to have a material  effect on the  financial
condition of the Company.

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

None


                                       28

<PAGE>



                                     PART II


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

At January 31,  1996,  the Company  had 92,542  registered  holders of record of
common stock.

The common stock of the Company is traded on the New York Stock Exchange and the
Pacific  Stock  Exchange.  Certain of the Company's  preferred  stock series are
traded on the New York Stock Exchange.

Information  respecting the high and low sales prices and the dividends declared
on the  Company's  common  stock  during  the past two years is set forth in the
table below.


                                   1995                         1994
                           Market      Dividends      Market           Dividends
                           Prices      Declared       Prices           Declared
                                       Per Share                       Per share
                  High        Low                    High       Low

1st Quarter      $16 3/4    $13 1/4     $0.445      $24 1/4   $21 1/2   $0.445
2nd Quarter       17 1/8     14 3/8      0.445      22  7/8   17  1/2    0.445
3rd Quarter       17 3/4     15 3/8      0.445      19  3/8   15         0.445
4th Quarter       17 3/4     15 5/8      0.445      18  1/8   15  1/4    0.445




                                       29

<PAGE>

<TABLE>
<CAPTION>

ITEM 6:  SELECTED FINANCIAL DATA
                                                                                (In thousands of dollars except per share amounts)
                                                                 1995            1994         1993              1992          1991
SUMMARY OF OPERATIONS                                                                                                       Table 1
<S>                                                         <C>             <C>            <C>            <C>           <C>      
Revenues                                                   $  3,075,128    $ 3,067,307   $  2,880,995   $  2,621,839   $ 2,547,729
Operating expenses                                            2,343,510      2,322,362      2,125,444      1,880,734     1,762,449
Operating income                                                731,618        744,945        755,551        741,105       785,280
Other income and (deductions)                                    43,703         52,719         70,874         66,330        40,482
Income before interest charges                                  775,321        797,664        826,425        807,435       825,762
Interest charges                                                472,035        495,812        529,862        505,461       520,224
Net income                                                      303,286        301,852        296,563        301,974       305,538
Preferred stock dividend requirements                            52,620         53,020         56,108         63,954        66,394
Earnings for Common Stock                                  $    250,666    $   248,832   $    240,455   $    238,020   $   239,144
Average common shares outstanding (000)                         119,195        115,880        112,057        111,439       111,348
Earnings per Common Share                                  $       2.10    $      2.15   $       2.15   $       2.14   $      2.15

Common stock dividends declared per share                  $       1.78    $      1.78   $       1.76   $       1.72   $      1.60
Common stock dividends paid per share                      $       1.78    $      1.78   $       1.75   $       1.71   $      1.55
Book value per common share at December 31                 $      20.50    $     20.21   $      19.88   $      19.58   $     19.13
Common shares outstanding
   at December 31 (000)                                         119,655        118,417        112,332        111,600       111,365
Common shareowners of record at December 31                      93,088         96,491         94,877         86,111        90,435


CAPITALIZATION RATIOS*                                                                                                      Table 2
Long-term debt                                                     61.8%          62.5%          65.0%          64.7%        63.9%
Preferred stock                                                     8.6            8.6            8.5            8.8          8.8
Common equity                                                      29.6           28.9           26.5           26.5         27.3
Total                                                            100.0%          100.0%         100.0%         100.0%       100.0%
*Includes   current   maturities  of  long-term  debt  and
current redemption requirements of preferred stock.


                                                                                                           (In thousands of dollars)
OPERATIONS AND MAINTENANCE EXPENSE DETAILS                                                                                 Table 3
Payroll and employee benefits                              $     440,721    $   435,830   $    418,766   $    420,297  $   403,983
Less - Charged to construction and other                         165,733        155,766        130,432        131,447      121,911
Payroll and employee benefits charged to
   operations                                                    274,988        280,064        288,334        288,850      282,072
Fuel and Purchased Power
Fuel - electric operations                                       266,039        261,154        287,349        282,138      354,859
Fuel - gas operations                                            264,282        267,629        253,511        206,344      172,992
Purchased power costs                                            309,807        307,584        292,136        280,914      197,154
Fuel cost adjustments deferred                                   (5,149)         11,619         (5,405)       (27,612)      43,697
Total fuel and purchased power                                   834,979        847,986        827,591        741,784      768,702
All other                                                        236,405        260,590        233,326        209,095      240,687
Total Operations and Maintenance Expense                   $   1,346,372    $ 1,388,640   $  1,349,251   $  1,239,729  $ 1,291,461

FULL-TIME EMPLOYEES AT DECEMBER 31                                 5,688          5,947          6,215          6,438        6,538
</TABLE>

                                      30
<PAGE>
<TABLE>
<CAPTION>
                                                                                                           (In thousands of dollars)
ELECTRIC OPERATING INCOME                                                                                                   Table 4
                                                      1995             1994            1993            1992              1991 
REVENUES
<S>                                                 <C>             <C>             <C>             <C>              <C>      
Residential                                      $  1,204,987    $  1,202,124    $  1,145,891    $  1,045,799    $   1,047,490
Commercial and industrial                           1,194,014       1,196,422       1,132,487       1,076,302        1,070,098
Other system revenues                                  52,472          52,477          49,790          49,395           47,838
Total system revenues                               2,451,473       2,451,023       2,328,168       2,171,496        2,165,426
Sales to other utilities                               19,104          14,895          12,872           9,997           23,040
Other revenues                                         13,437          15,719          11,069          13,139            8,102
Total Revenues                                      2,484,014       2,481,637       2,352,109       2,194,632        2,196,568
OPERATING EXPENSES
Operations - fuel and purchased power                 570,697         568,738         579,032         559,583          593,656
Operations - other                                    293,184         310,438         306,116         294,909          296,798
Maintenance                                           106,031         107,573         111,765         105,341          127,446
Depreciation and amortization                         121,980         111,996         106,149         104,034          104,172
Base financial component amortization                 100,971         100,971         100,971         100,971          100,971
Rate moderation component amortization                 21,933         197,656          88,667         (30,444)        (228,572)
Regulatory liability component amortization           (79,359)        (79,359)        (79,359)        (79,359)         (79,359)
1989 Settlement credits amortization                   (9,214)         (9,214)         (9,214)         (9,214)          (9,214)
Other regulatory amortization                         155,532          (4,883)        (17,082)        (21,984)          10,375
Operating taxes                                       375,164         336,263         326,407         331,122          338,429
Federal income tax - current                           14,596          10,784           6,324             530              515
Federal income tax - deferred and other               168,377         156,646         158,941         158,908          173,259
Total Operating Expenses                            1,839,892       1,807,609       1,678,717       1,514,397        1,428,476
Electric Operating Income                        $    644,122    $    674,028    $    673,392    $    680,235    $     768,092

                                                                                                           (In thousands of dollars)
GAS OPERATING INCOME                                                                                                        Table 5

REVENUES
Residential - space heating                      $    323,729    $    326,474    $    310,109    $    243,950    $     190,976
                     - other                           42,046          42,263          39,515          33,035           29,383
Commercial and industrial - space heating             130,964         126,092         106,140          90,363           70,938
                          - other                      34,293          35,275          33,181          29,094           25,515
Total firm revenues                                   531,032         530,104         488,945         396,442          316,812
Interruptible revenues                                 32,837          26,804          24,028          19,658           21,686
Total system revenues                                 563,869         556,908         512,973         416,100          338,498
Off-system revenues, net                               16,213          20,904           5,812             -               -
Other revenues                                         11,032           7,858          10,101          11,107           12,663
Total Revenues                                        591,114         585,670         528,886         427,207          351,161
OPERATING EXPENSES
Operations - fuel                                     264,282         279,248         248,559         182,201          175,046
Operations - other                                     90,054          95,576          81,692          77,300           78,469
Maintenance                                            22,124          27,067          22,087          20,395           20,046
Depreciation and amortization                          23,377          18,668          16,322          15,103           14,783
Other regulatory amortization                           6,073           9,211            (962)            (88)              -
Operating taxes                                        72,343          70,632          59,440          57,866           49,951
Federal income tax - deferred and other                25,365          14,351          19,589          13,560          (4,322)
Total Operating Expenses                              503,618         514,753         446,727         366,337         333,973
Gas Operating Income                             $     87,496    $     70,917    $     82,159    $     60,870    $     17,188

</TABLE>

                                       31
<PAGE>
<TABLE>
<CAPTION>
                                                       1995          1994            1993            1992             1991
ELECTRIC SALES AND CUSTOMERS                                                                                       Table 6
SALES - MILLIONS OF KWH
<S>                                                   <C>           <C>             <C>             <C>              <C>  
Residential                                           7,156         7,159           7,118           6,788            7,022
Commercial and industrial                             8,336         8,394           8,257           8,181            8,322
Other system sales                                      460           457             449             471              469
Total system sales                                   15,952        16,010          15,824          15,440           15,813
Sales to other utilities                                620           372             304             227              598
Total Sales                                          16,572        16,382          16,128          15,667           16,411
CUSTOMERS - MONTHLY AVERAGE
Residential                                         915,162       908,490         905,997         902,885          898,974
Commercial and industrial                           103,669       102,490         102,254         101,838          101,740
Other                                                 4,549         4,583           4,553           4,593            4,540
TOTAL CUSTOMERS - MONTHLY AVERAGE                 1,023,380     1,015,563       1,012,804       1,009,316        1,005,254
CUSTOMERS - AT DECEMBER 31                        1,025,107     1,016,739       1,011,965       1,009,028        1,005,363
RESIDENTIAL
kWh per customer                                      7,819         7,880           7,857           7,518            7,811
Revenue per kWh                                       16.84         16.79           16.10           15.41            14.92
COMMERCIAL AND INDUSTRIAL
kWh per customer                                     80,410        81,901          80,750          80,333           81,797
Revenue per kWh                                       14.32         14.25           13.72           13.16            12.86
SYSTEM
kWh per customer                                     15,588        15,765          15,624          15,297           15,730
Revenue per kWh                                       15.37         15.31           14.71           14.06            13.69



GAS SALES AND CUSTOMERS                                                                                            Table 7
SALES - THOUSANDS OF DTH
Residential - space heating                          35,336        35,693          37,191          35,089           29,687
            - other                                   2,929         3,151           3,297           3,203            3,195
Commercial and industrial - space heating            16,170        15,679          14,366          13,662           11,636
                          - other                     4,269         4,366           4,329           4,338            4,171
Total firm sales                                     58,704        58,889          59,183          56,292           48,689
Interruptible sales                                   9,176         6,914           5,920           5,090            4,538
Off-system sales                                      7,743         7,232           2,894               -                -
Total Sales                                          75,623        73,035          67,997          61,382           53,227
CUSTOMERS - MONTHLY AVERAGE
Residential  - space heating                        245,452       239,857         233,882         227,834          220,562
             - other                                162,114       163,608         166,974         169,189          171,581
Commercial and industrial - space heating            35,027        33,776          32,783          31,666           30,453
                          - other                    10,313        10,448          10,631          10,777           11,003
Total firm customers                                452,906       447,689         444,270         439,466          433,599
Interruptible customers                                 623           576             542             531              472
TOTAL CUSTOMERS  - MONTHLY AVERAGE                  453,529       448,265         444,812         439,997          434,071
CUSTOMERS - AT DECEMBER 31                          455,869       449,906         446,384         442,117          436,853
RESIDENTIAL
dth per customer                                       93.9          96.3           101.0            96.4             83.9
Revenue per dth                                 $      9.56        $ 9.49     $      8.64    $       7.23     $       6.70
COMMERCIAL AND INDUSTRIAL
dth per customer                                      450.8         453.3           430.6           424.1            381.3
Revenue per dth                                 $      8.09       $  8.05     $      7.45    $       6.64     $       6.10
SYSTEM
dth per customer                                      149.7         146.8           146.4           139.5            122.6
Revenue per dth                                 $      8.31       $  8.46     $      7.88    $       6.78     $       6.36

</TABLE>
                                       32
<PAGE>
<TABLE>
<CAPTION>
                                                                                                               Table 8
ELECTRIC OPERATIONS                                      1995         1994        1993           1992             1991
ENERGY - MILLIONS OF KWH
<S>                                                     <C>          <C>         <C>            <C>              <C>  
Net generation                                         10,744       10,034      10,514         10,592           13,570
Power purchased                                         7,143        7,640       7,023          6,438            4,236
Total Energy Available                                 17,887       17,674      17,537         17,030           17,806

System sales                                           15,952       16,010      15,824         15,440           15,813
Company use and unaccounted for                         1,315        1,292       1,409          1,363            1,395
Total system energy requirements                       17,267       17,302      17,233         16,803           17,208
Sales to other utilities                                  620          372         304            227              598
Total Energy Available                                 17,887       17,674      17,537         17,030           17,806

PEAK DEMAND - MW
Station coincident demand                               3,591        3,253       2,931          2,975            3,085
Power purchased - net                                     486          629       1,036            636              819
System Peak Demand                                      4,077        3,882       3,967          3,611            3,904
System Capablility  - MW
Company stations                                        3,957        4,063       4,063          4,091            4,078
Nine Mile Point 2 (18% share)                             203          189         188            188              194
Firm purchases - net                                      713          616         548            432              423
Total Capability                                        4,873        4,868       4,799          4,711            4,695
FUEL CONSUMED FOR ELECTRIC OPERATIONS
Oil - thousands of barrels                              5,154        7,518       9,740         10,656           15,314
Gas - thousands of dth                                 69,826       44,308      36,269         34,475           32,924
Nuclear - thousands of MW days - thermal                  169          203         175            124              154

FUEL MIX (PERCENTAGE OF TOTAL ENERGY AVAILABLE)
Oil                                                        17%         25%          34%            37%              50%
Gas                                                        36           23          19             19               18
Purchased power                                            40           43          40             38               25
Nuclear fuel                                                7            9           7              6                7
Total                                                     100%         100%        100%           100%             100%

                                                                                                               Table 9
GAS OPERATIONS
COMPANY REQUIREMENTS-THOUSANDS OF DTH
System sales                                           67,880       65,803      65,103         61,382           53,227
Off-system sales                                        7,743        7,232       2,894              0                0
Company use and unaccounted for                         2,054        2,516       1,905          3,577            2,412
Total Company Requirements                             77,677       75,551      69,902         64,959           55,639
MAXIMUM DAY SENDOUT - DTH                             564,874      585,227     485,896        448,726          435,050
SYSTEM CAPABILITY - DTH PER DAY
Natural gas                                           592,335      579,897     561,584        561,584          507,344
LNG manufactured or LP gas                            124,700      125,700     120,700        120,700          128,200
Total Capability                                      717,035      705,597     682,284        682,284          635,544
HEATING DEGREE DAYS
(30 year average 4,969)                                 4,906        4,839       4,899          5,066            4,378

</TABLE>
                                       33
<PAGE>
<TABLE>
<CAPTION>

                                                                                                          (In thousands of dollars)
                                                             1995            1994          1993             1992          1991
BALANCE SHEET                                                                                                           Table 10
ASSETS
<S>                                                    <C>            <C>            <C>            <C>             <C> 
Net utility plant                                      $  3,594,998   $   3,498,346  $   3,347,557  $   3,161,148   $  3,002,733   
Regulatory Assets
  Base financial component                                3,382,519       3,483,490      3,584,461      3,685,432      3,786,403
  Rate moderation component                                 383,086         463,229        609,827        651,657        602,053
  Shoreham post-settlement costs                            968,999         922,580        777,103        586,045        378,386
  Shoreham nuclear fuel                                      71,244          73,371         75,497         77,629         79,760
  Unamortized cost of issuing securities                    222,567         254,482        174,694        195,524        168,405
  Postretirement benefits other than pensions               383,642         412,727        402,921              -              -
  Regulatory tax asset                                    1,802,383       1,831,689      1,848,998              -              -
  Other                                                     230,663         250,804        247,858        190,008        131,143
Total Regulatory Assets                                   7,445,103       7,692,372      7,721,359      5,386,295      5,146,150
Nonutility property and other investments                    16,030          24,043         23,029         20,730          9,788
Current assets                                            1,407,215       1,091,381      1,075,561        961,532        859,242
Deferred charges                                             21,023         172,768        286,005        323,418        681,347
Total Assets                                             12,484,369   $  12,478,910  $  12,453,511  $   9,853,123   $  9,699,260

CAPITALIZATION AND LIABILITIES
Long-term debt                                         $   4,722,675   $   5,162,675  $   4,887,733  $   4,755,733   $  5,001,016 
Unamortized discount on debt                                (16,075)        (17,278)       (17,393)       (14,731)       (14,850)
                                                          4,706,600       5,145,397      4,870,340      4,741,002      4,986,166
Preferred stock - redemption required                       639,550         644,350        649,150        557,900        524,912
Preferred stock - no redemption required                     63,934          63,957         64,038        154,276        154,371
Total Preferred Stock                                       703,484         708,307        713,188        712,176        679,283
Common stock                                                598,277         592,083        561,662        558,002        556,825
Premium on capital stock                                  1,114,508       1,101,240      1,010,283        998,089        993,509
Capital stock expense                                       (50,751)        (52,175)       (50,427)       (39,304)       (40,216)
Retained earnings                                           790,919         752,480        711,432        667,988        620,373
Total Common Shareowners' Equity                          2,452,953       2,393,628      2,232,950      2,184,775      2,130,491
Total Capitalization                                      7,863,037       8,247,332      7,816,478      7,637,953      7,795,940
Regulatory Liabilities
  Regulatory liability component                            277,757         357,117        436,476        515,835        595,194
  1989 Settlement credits                                   136,655         145,868        155,081        164,294        173,507
  Regulatory tax liability                                  116,060         111,218        114,748              -              -
  Other                                                     132,694         147,041        142,455        102,718         74,858
Total Regulatory Liabilities                                663,166         761,244        848,760        782,847        843,559
Current liabilities                                       1,032,781         601,311      1,188,972      1,177,130        492,895
Deferred credits                                          2,476,249       2,365,401      2,166,145        237,893        559,559
Operating reserves                                          449,136         503,622        433,156         17,300          7,307
Total Capitalization and Liabilities                    $12,484,369   $  12,478,910  $  12,453,511  $   9,853,123   $  9,699,260 
                                                                                                          (In thousands of dollars)
CONSTRUCTION EXPENDITURES*                                                                                              Table 11
Electric                                                 $  145,472   $     136,041  $     137,583  $     141,752   $    129,643 
Gas                                                          79,536         120,019        124,859        104,028         89,950
Common                                                       21,477          23,610         42,251         27,124         17,958
Total Construction Expenditures                             246,485   $     279,670  $     304,693  $     272,904   $    237,551

</TABLE>

*Includes  non-cash  allowance  for other  funds used  during  construction  and
excludes Shoreham post-settlement costs.

                                       34
<PAGE>


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

This discussion and analysis  addresses  matters of significance  with regard to
the Company and its financial  condition,  liquidity,  capital  requirements and
results of operations for the last three years.

OVERVIEW

As  the  utility  industry  continues  the  transition  to  a  more  competitive
marketplace,  the pressure from customers and regulators to reduce rates on Long
Island has intensified. This pressure to reduce rates has resulted in an attempt
by the Long Island Power Authority  (LIPA),  an agency of the State of New York,
to develop a plan to replace the Company as the primary electric and gas utility
on Long Island.  The Company's response to these challenges has been to continue
a strategic plan designed to avoid future rate  increases  through an aggressive
cost containment program,  while maintaining a reliable electric and gas system.
The Company  believes  that these efforts will allow it to improve its financial
health  and better  position  itself for the  transition  to a more  competitive
environment.


SIGNIFICANT ACHIEVEMENTS DURING 1995 INCLUDED:

     o  Cash generated from operations exceeded the Company's operating,
        construction and refunding requirements;

     o The  extinguishment  of the  First  Mortgage  debt  with  cash  on  hand,
       resulting in an improvement in the Company's debt ratio;

     o  Earnings per common share of $2.10,  despite a lower  allowed  return on
        common  equity  and  the   modification  of  certain   performance-based
        incentives related to the electric business;

     o  The continuation of the Company's quarterly common stock dividend
        rate at 44 1/2 cents per share;

     o  Continuation of the electric rate freeze for the second consecutive
        year;

     o  A reduction in the Rate Moderation  Component  balance from $463 million
        at December 31, 1994 to $383 million at December 31, 1995;

     o  The  establishment  of a record  peak  electric  energy  demand of 4,077
        megawatts  on  August  4,  1995,  surpassing  the old  record  of  3,967
        megawatts on July 9, 1993;

     o  Receipt of a 3.2% gas rate increase effective December 1, 1995, which is
        the  final of three gas rate  increases  under a  three-year  settlement
        between the Company and the Public Service Commission of

                                       35
<PAGE>
        the State of New York;

     o  The addition of over 6,500 new gas space  heating  customers,  resulting
        from the continuation of the Company's gas expansion program;

     o  A reduction in the level of construction expenditures and operations
        and maintenance expenses;

     o  A reduction in staff levels through attrition while reducing
        overtime payments;

     o  Receipt  of final  regulatory  approval  of the  decommissioning  of the
        Shoreham Nuclear Power Station.

As part of its  strategic  effort  to  improve  its  competitive  position,  the
Company,  for the rate years ended  November 30, 1995 and 1996,  froze  electric
rates by focusing on cost  reduction.  The Company's  cost  reduction  programs,
which seek to maximize  operating  efficiencies  as a means to reduce  operating
costs,  resulted in reducing  non-fuel  operations and  maintenance  expenses by
approximately $29 million from the 1994 amount.

During 1995,  the Company  continued its policy of not  replacing  employees who
decided to either retire or terminate  employment with the Company. The benefits
derived from internal  process review  programs and the Company's  commitment to
reallocate existing resources have allowed the Company to operate with increased
efficiencies despite the loss, through attrition,  of 857 employees or about 13%
of it's workforce  since 1990. In 1995,  the Company's  workforce was reduced by
259 employees or about 5%.

In addition to reducing its operations and maintenance expense, the Company also
reduced its capital  expenditures  by  approximately  $130 million in 1995,  due
primarily to the  completion,  in 1994, of the  decommissioning  of the Shoreham
Nuclear Power Station (Shoreham).  However, the Company's commitment to increase
penetration  in the gas home heating market on Long Island  remains  strong.  In
1995, the Company invested approximately $50 million into its gas infrastructure
to increase safety,  reliability and availability of gas in order to attract new
gas space heating customers.

As a  result  of the  above,  the  Company,  for the  second  consecutive  year,
generated  sufficient  cash flow to meet all of its operating  and  construction
requirements.  This  enhanced  cash flow also  allowed the Company to redeem all
amounts outstanding under the First Mortgage with cash on hand.


                                       36
<PAGE>



LONG ISLAND POWER AUTHORITY PROPOSED PLAN

During  1995,  the  Governor  of the State of New York  requested  that the Long
Island Power Authority  (LIPA) develop a plan that, in addition to replacing the
Company as the  primary  electric  and gas utility on Long  Island,  would among
other  things,  produce an electric  rate  reduction of at least 10%,  provide a
framework for long-term  competition in power  production  and protect  property
taxpayers on Long Island. In response to this request,  the Board of Trustees of
LIPA  established a committee  (Evaluation  Committee) to analyze  various plans
involving the Company's business operations and assets.

In December 1995, after soliciting  information and indications of interest from
various    parties   in   connection   with   a    LIPA-facilitated    financial
restructuring/acquisition   of  the  Company,  the  members  of  the  Evaluation
Committee  and their  advisors  announced  a proposed  plan to  restructure  the
Company and reduce  electric  rates on Long Island by 12% (Proposed  Plan).  The
Proposed  Plan,  which  has not  been  adopted  by the LIPA  Board  or  formally
presented to the  Company's  Board of  Directors  for  consideration,  generally
provides  that:  (i) the  Company  sell,  subject  to LIPA's  approval,  its gas
business and  electric  generation  assets;  (ii) LIPA  purchase  the  Company's
transmission,  distribution and  Shoreham-related  assets; (iii) LIPA enter into
long-term  power  purchase  agreements  with the  purchasers  of the  generation
assets;  (iv)  LIPA  enter  into  agreements  with  contractors  to  manage  the
transmission and distribution system; and (v) LIPA exercise its power of eminent
domain over all or a portion of the  Company's  assets or securities in order to
achieve its  objectives  if a  negotiated  agreement  cannot be reached with the
Company.

The Company has  indicated  to LIPA that certain  elements of the Proposed  Plan
raise  significant  concerns.   Specifically,  the  Proposed  Plan  contains  no
information  regarding  the  values  or prices  contemplated  to be paid for the
Company's  assets,  no  financing  commitments  for any portion of the  proposed
transaction were disclosed and no indications that endorsements by certain State
officials  required  to approve  any  transaction  undertaken  by LIPA have been
obtained. In addition, based on the limited information currently available, the
Company is unable to  determine  how the  anticipated  rate  reduction  would be
achieved  and  how the  reliability  of the  electric  system,  including  storm
restoration  capabilities,  would be maintained given the multiple entities that
would be responsible for providing such service.

Notwithstanding  these  concerns,  the Company remains willing to cooperate with
LIPA  in  developing  a plan  that is  beneficial  to the  Company's  investors,
customers and employees.  The Company is  continuously  assessing  various other
strategies  in  an  effort  to  provide  the  greatest  possible  value  to  its
constituents  in  light  of the  changing  economic,  regulatory  and  political
challenges  affecting  the  Company.  Such  strategies  may include a review and
modification  of its  operations  to best meet the  challenges  of a competitive
environment,  a possible reorganization of the Company, potential joint ventures
and/or possible business combinations with other entities.


                                       37
<PAGE>



The implementation of certain plans involving the Company's business  operations
and assets would be subject to, among other things,  shareholder  and regulatory
approvals  and  could  impact  the  Company's  future   financial   results  and
operations.  Accordingly,  the Company is unable to determine what plan, if any,
will be pursued by it and/or  LIPA or whether any  related  transaction  will be
consummated.

COMPETITIVE ENVIRONMENT

The electric industry  continues to undergo  fundamental  changes as regulators,
elected officials and customers seek lower energy prices.  These changes,  which
may have a  significant  impact  on future  financial  performance  of  electric
utilities,  are being  driven  by a number of  factors  including  a  regulatory
environment in which traditional  cost-based  regulation is seen as a barrier to
lower energy prices. In 1995, both the Public Service Commission of the State of
New York (PSC) and the Federal Energy  Regulatory  Commission  (FERC)  continued
their  separate  initiatives  with  respect  to  developing  a  framework  for a
competitive electric marketplace.

New York State Competitive Opportunities Proceedings

In  1994,  the PSC  began  the  second  phase of its  Competitive  Opportunities
Proceedings  to  investigate  issues  related  to the  future of the  regulatory
process in an industry  which is moving  toward  competition.  The PSC's overall
objective was to identify regulatory and ratemaking  practices that would assist
New York State  utilities in the  transition to a more  competitive  environment
designed to increase efficiency in providing electricity while maintaining safe,
affordable and reliable service.

During  1995,  the  proceedings  continued  with the PSC  adopting  a series  of
principles  which it will use to guide the  transition  of the electric  utility
industry  in New York State  from a  rate-regulated  cost of service  model to a
competitive market-driven model. The principles state, among other things, that:
(i)  consumers  should have a  reasonable  opportunity  to realize  savings from
competition; (ii) a basic level of reasonably priced service must be maintained;
(iii)  the  integrity,  safety  and  reliability  of the  system  should  not be
jeopardized; and (iv) the current industry structure, in which most power plants
are vertically  integrated with natural  monopoly  transmission and distribution
systems,  should be  thoroughly  examined  to ensure  that it does not impede or
obstruct the  development  of  effective  wholesale  or retail  competition.  In
addition,   the  principles  state  that  utilities  should  have  a  reasonable
opportunity to recover prudent and verifiable  expenditures and commitments made
pursuant to their legal obligations, consistent with these principles.

In October 1995, the Energy  Association,  which is comprised of the Company and
the six other investor-owned New York State utilities, filed a proposal designed
to achieve the principles  outlined by the PSC. The proposal,  which is referred
to as the  "Wholesale  Poolco  Model",  establishes a framework  that will allow
competition  at the wholesale  level.  The plan would,  among other things:  (i)
allow utilities, non-regulated generators

                                       38
<PAGE>



and other market  participants to create a wholesale exchange that allows market
forces to  determine  the price of  wholesale  electricity;  (ii)  establish  an
Independent  System Operator (ISO) to coordinate the safe and reliable operation
of the bulk  power  transmission  system;  (iii)  increase  customer  choice  by
providing clear market price signals so customers can make informed decisions on
the use of electricity;  and (iv) separate the generation portion of a utility's
business from its regulated transmission and distribution business.

In this model,  competing  generating  suppliers would bid energy sales into the
market.  The market  clearing price for energy would be determined by the bid of
the  highest  price  unit  needed  to serve the load in a  particular  location.
Regulated utility  companies could purchase energy from the market,  which would
establish  a half-hour  locational  spot market  price for  electricity,  or the
utility could seek to enter into bilateral energy agreements with other parties.
Bilateral  agreements  would  be  administered  independently  of the  wholesale
exchange,  but would be scheduled  through the ISO. These  bilateral  agreements
would be permitted  among  utility  companies,  generating  companies  and power
marketers. In the Wholesale Poolco Model, the purchase of electricity by end use
customers would still be bundled with  transmission,  distribution  and customer
service, all of which would be provided by regulated utilities.

The support of the New York State  utilities for the  Wholesale  Poolco Model is
predicated on a number of factors,  including:  (i) a reasonable  opportunity to
fully recover all investments and expenditures  made to provide reliable service
under the existing regulatory  compact;  (ii) PSC support for the option of each
utility to continue in the  generation  business;  (iii)  special  treatment  of
nuclear plants based on their unique characteristics; and (iv) the adoption of a
clearly defined transition plan to ensure that the interests of the customer and
the investor are adequately protected.

In  December  1995,  an  Administrative  Law  Judge  (ALJ)  of the PSC  issued a
Recommended   Decision  (RD)  to  the  PSC  with  respect  to  this  Competitive
Opportunities  Proceedings.  The ALJ recommended a competitive model which seeks
to  transition  the electric  utility  industry in New York State to full retail
competition through two stages. The first stage of this recommendation  seeks to
transition  the industry  from its current cost of service rate  regulation to a
competitive  wholesale model similar to the Wholesale  Poolco Model.  This first
stage  would allow  participants  to become  familiar  with the  operation  of a
deregulated,  competitive  generation  market prior to the eventual  movement to
full  retail  competition  in the  second  stage,  through a model  known as the
Flexible Retail Poolco Model.

The Flexible Retail Poolco Model contains many of the same attributes associated
with the Wholesale  Poolco Model,  including:  (i) an ISO to coordinate the safe
and reliable  operation of generation and transmission;  (ii) open access to the
transmission   system,   which  would  be  regulated  by  FERC;  and  (iii)  the
continuation  of a regulated  distribution  company to operate and  maintain the
distribution  system.  The  principal  difference  between  the  models  is that
customers would have a choice among suppliers of

                                       39
<PAGE>


electricity in the Flexible Retail Poolco Model whereas in the Wholesale  Poolco
Model,  the regulated  entity would acquire electric energy from the spot energy
sales exchange to sell to the customer.

The Flexible  Retail  Poolco Model would also:  (i)  deregulate  energy/customer
services such as meter reading and customer billing;  (ii) unbundle  electricity
into   four   components:    generation,    transmission,    distribution,   and
energy/customer  services;  and  (iii)  provide  customers  with a choice  among
suppliers of electricity,  and allow customers to acquire  electricity either by
long-term contracts or purchases on the spot market or a combination of the two.

One of the most contentious issues of the Competitive  Opportunities Proceedings
has been the position  taken by the various  parties to the  proceedings  on the
amount of recovery  utilities  should be permitted to collect from customers for
so-called  stranded  investments.  Stranded  investments  represent  costs  that
utilities would have otherwise recovered through rates under traditional cost of
service regulation that, under competition, utilities may not be able to recover
since the market  price for their  product may be  inadequate  to recover  these
costs.  The Staff of the PSC, for example,  has indicated that utilities  should
not expect full recovery of stranded costs. The Energy Association has commented
that  utilities  have a sound legal  precedent  confirmed by  long-standing  PSC
policy to fully recover all prudently incurred costs,  including stranded costs.
The RD states that for recovery,  stranded costs must be prudent, verifiable and
unable to be reduced through mitigation measures. The RD states that recovery of
stranded  costs be predicated on the prudency of the costs  incurred.  The costs
must be  verifiable  and the  Company  must  show  that it was  unable  to avoid
incurring these costs.

The RD states that a generic decision should address the definition,  the method
of measurement, the requirements for mitigation, a preferable recovery mechanism
and a standard for the recovery of stranded investments.  The calculation of the
amount to be recovered  from  customers,  however,  should be left to individual
rate cases or special  proceedings that should begin during 1996. The RD further
directs New York State investor-owned utilities to individually file, within six
months of the PSC's order, a  comprehensive  long-term  proposal  addressing the
significant components of the RD.

It is not possible to predict the  ultimate  outcome of these  proceedings,  the
timing thereof,  or the amount, if any, of stranded costs that the Company would
recover in a competitive  environment.  The outcome of these  proceedings  could
adversely  affect  the  Company's   ability  to  apply  Statement  of  Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation", which, pursuant to SFAS No. 101, "Accounting for Discontinuation
of Application of SFAS No. 71" and SFAS No. 121,  "Accounting for the Impairment
of Long-Lived  Assets and for  Long-Lived  Assets to be Disposed Of," could then
require a significant write-down of assets, the amount of which cannot presently
be  determined.  For a further  discussion  of SFAS No. 71 and SFAS No. 121, see
Note 1 of Notes to Financial Statements.

                                       40
<PAGE>



The Electric Industry - Federal Regulatory Issues

As a result of Congress' passage of the Public Utility  Regulatory  Policies Act
of 1978 (PURPA),  and the National  Energy  Policy Act of 1992 (NEPA),  the once
monopolistic electric utility industry now faces competition.

PURPA's  goal is to  reduce  the  United  States'  dependence  on  foreign  oil,
encourage  energy  conservation  and  promote  diversification  of fuel  supply.
Accordingly,  PURPA  provided  for the  development  of a new class of  electric
generators which rely on either cogeneration  technology or alternate fuels. The
utilities are  obligated  under PURPA to purchase the output of certain of these
new generators, which are known as qualified facilities (QFs).

NEPA sought to increase economic  efficiency in the creation and distribution of
power by relaxing  restrictions on the entry of new competitors to the wholesale
electric  power  market  (i.e.,  sales to an entity for  resale to the  ultimate
consumer).  NEPA does so by creating exempt  wholesale  generators that can sell
power in wholesale markets without the regulatory  constraints placed on utility
generators  such as the Company.  NEPA also expanded  FERC's  authority to grant
access  to  utility  transmission  systems  to all  parties  who seek  wholesale
wheeling for  wholesale  competition.  Significant  issues  associated  with the
removal of restrictions on wholesale  transmission  system access have yet to be
resolved and the potential impact on the Company's financial position cannot yet
be determined.

FERC is in the  process  of setting  policy  which will  largely  determine  how
wholesale competition will be implemented. FERC has declared that utilities must
provide wholesale wheeling to others that is comparable to the service utilities
provide  themselves.  FERC has  issued  policy  statements  concerning  regional
transmission  groups,  transmission  information  requirements  and "good faith"
requests  for service and  transmission  pricing.  In March 1995,  FERC issued a
Notice  of  Proposed  Rulemaking  (NOPR)  which  combined  the  issues  of  open
transmission  access and stranded  cost  recovery.  The NOPR  contained a strong
endorsement of the right of the utilities to full recovery of stranded costs due
to wholesale wheeling and retail-turned-wholesale wheeling arrangements.  During
the year,  FERC has  followed up on these issues  through an  extensive  comment
period,  holding public hearings on pro-forma  transmission  tariffs,  ancillary
services,  real-time information systems and power pooling issues. FERC recently
announced its interest in exploring  the role of an ISO in providing  comparable
transmission  access.  It is expected that FERC will issue a final order on open
access in 1996. Utilities,  including the Company, and numerous other interested
parties are actively involved in these proceedings.

It is not possible to predict the outcome of these proceedings or the effect, if
any, on the financial condition of the Company.  The Company participates in the
wholesale  electricity  market  primarily as a buyer,  and in this regard should
benefit if rules are  adopted  which  result in lower  wholesale  prices for its
retail customers.

                                       41
<PAGE>



The Company's Service Territory

The changing utility regulatory environment has affected the Company in a number
of ways. For example,  PURPA's  encouragement of the non-utility generator (NUG)
industry has negatively impacted the Company. In 1995, the Company lost sales to
NUGs totaling 366 gigawatt-hours  (Gwh) representing a loss in electric revenues
net of  fuel  (net  revenues)  of  approximately  $28  million,  or  1.5% of the
Company's net revenues. In 1994, the Company lost sales to NUGs totaling 237 Gwh
or approximately $24 million of net revenues.  The increase in lost net revenues
resulted principally from the completion,  in April 1995, of a QF located at the
State University of New York at Stony Brook, New York (Stony Brook Project). The
annual  load  loss  due to this  QF is  estimated  to be 188  Gwh.  The  Company
estimates that in 1996,  sales losses to NUGs will be 414 Gwh, or  approximately
1.7% of projected  net revenues,  an increase  reflecting 12 months of operation
for the Stony Brook Project.  The Company  believes that load losses due to NUGs
have  stabilized.  This belief is based on the fact that the Company's  customer
load characteristics, which lack a significant industrial base and related large
thermal load, will mitigate load loss and thereby make cogeneration economically
unattractive.

Additionally,  as mentioned  above,  the Company is required to purchase all the
power offered by QFs which in 1995 and 1994 approximated 205 megawatts (MW). QFs
have the choice of pricing  sales to the  Company at either the PSC's  published
estimates of the  Company's  long-range  avoided  costs (LRAC) or the  Company's
tariff  rates,  which are modified from time to time,  reflecting  the Company's
actual avoided costs.  Additionally,  until repealed in 1992, New York State law
set a minimum price of six cents per  kilowatt-hour  (kWh) for utility purchases
of power  from  certain  categories  of QFs,  considerably  above the  Company's
avoided  cost.  The six cent minimum now only applies to contracts  entered into
before June 1992. The Company  believes that the repeal of the six cent minimum,
coupled  with recent PSC updates  which  resulted in lower LRAC  estimates,  has
significantly reduced the economic benefits of constructing new QFs. The Company
estimates  that  purchases  from QFs  required by federal and state law cost the
Company $53 million more than it would have cost had the Company  generated this
power in both 1995 and 1994.

The Company  has also  experienced  a revenue  loss as a result of its policy of
voluntarily  providing  wheeling of New York Power  Authority  (NYPA)  power for
economic  development.  The Company  estimates  that in 1995 and 1994 NYPA power
displaced   approximately   429  Gwh  and  400  Gwh  of  annual   energy  sales,
respectively.  The net  revenue  loss  associated  with this  amount of sales is
approximately  $30 million or 1.6% of the  Company's  1995 net  revenues and $28
million or 1.5% of the  Company's  1994 net revenues.  Currently,  the potential
loss of additional  load is limited by conditions in the Company's  transmission
agreements with NYPA.

Aside from NUGs, a number of customer groups are seeking to hasten consideration
and implementation of full retail competition. For example, an energy consultant
has  petitioned  the PSC,  seeking  alternate  sources of power for Long  Island
school districts. The County of Nassau has also


                                       42
<PAGE>



petitioned  the PSC to  authorize  retail  wheeling  for all classes of electric
customers in the county. In addition,  several towns and villages on Long Island
are    investigating    municipalization,    in   which    customers    form   a
government-sponsored  electric supply  company.  This is one form of competition
likely to  increase  as a result of NEPA.  The Town of  Southampton  and several
other towns in the Company's  service territory are considering the formation of
a  municipally  owned and  operated  electric  authority to replace the services
currently provided by the Company.  Suffolk County issued a request for proposal
from suppliers for up to 200 MW of power which the County would then sell to its
residential  and  commercial  customers.  The County has  awarded the bid to two
off-Long  Island  suppliers  and has requested the Company to deliver the power.
The Company has responded  that it does not believe the County is eligible under
present laws and regulations to purchase wholesale power and resell it to retail
customers,  and has declined to offer the requested retail wheeling service. The
Company's  geographic  location and the limited electrical  interconnections  to
Long  Island  serve to  limit  the  accessibility  of its  transmission  grid to
potential competitors from off the system.

The  matters  discussed  above  involve  substantial  social,  economic,  legal,
environmental and financial issues.  The Company is opposed to any proposal that
merely  shifts  costs  from one group of  customers  to  another,  that fails to
enhance the provision of least-cost,  efficiently-generated  electricity or that
fails to  provide  the  Company's  shareowners  with an  adequate  return on and
recovery of their  investment.  The Company is unable to predict what action, if
any, the PSC or FERC may take regarding any of these  matters,  or the impact on
the Company's  financial  condition if some or all of these matters are approved
or implemented by the appropriate regulatory authority.


Notwithstanding the outcome of the federal or state regulatory rate proceedings,
or any other state action,  the Company believes that, among other  obligations,
the State has a  contractual  obligation  to allow the  Company to  recover  its
Shoreham-related assets.

LIQUIDITY

During 1995,  cash generated from operations  exceeded the Company's  operating,
construction  and refunding  requirements  in addition to allowing for the early
redemption of the Company's  remaining First Mortgage Bonds.  This positive cash
flow is the result  of: (i) the  Company's  continuing  efforts to control  both
operations and maintenance (O&M) costs and construction expenditures; (ii) lower
fuel costs; (iii)  significantly lower costs incurred at Shoreham as a result of
the  completion  of the plant's  decommissioning  in 1994;  (iv) lower  interest
payments  resulting from lower debt levels; and (v) the collection of previously
deferred revenues.

At December  31,  1995,  the  Company's  cash and cash  equivalents  amounted to
approximately  $351  million,  compared to $185 million at December 31, 1994. In
addition, the Company has available for its use a $300 million revolving line of
credit through October 1, 1996,  provided by its 1989 Revolving Credit Agreement
(1989 RCA). This line of credit is secured by a first


                                       43
<PAGE>


lien upon the Company's  accounts  receivable  and fuel oil  inventories.  For a
further discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements.

In January  1996,  the Company  received  approximately  $81 million,  including
interest, from Suffolk County pursuant to a judgment in the Company's favor that
found that the  Shoreham  property  was  overvalued  for  property  tax purposes
between 1976 and 1983 (excluding  1979 which had previously  been settled).  The
Company  has  petitioned  the PSC to  allow  the  Company  to  reduce  the  Rate
Moderation  Component  (RMC) by the amount  received,  net of  litigation  costs
incurred by the  Company.  The Company is also  seeking  recovery  from  Suffolk
County for the overpayment of taxes on the Shoreham  property for the years 1984
through 1992 in a separate  proceeding which is currently pending before the New
York Supreme Court. For a further  discussion of this proceeding,  see "Shoreham
Related Litigation" below.

The Company  currently  believes  that it will not need to access the  financial
markets to retire its $415 million of maturing  debt in 1996 as cash balances on
hand at that time will be  sufficient  to support all Company  requirements  for
1996.  However,  the Company will avail itself of any tax-exempt  financing made
available to it by the New York State Energy Research and Development  Authority
(NYSERDA).  With  respect to the  repayment  of $251 million and $101 million of
debt maturing in 1997 and 1998,  respectively,  the Company  intends to use cash
generated from operations to the maximum extent practicable.

In 1990 and 1992,  the Company  received  Revenue  Agents'  Reports  disallowing
certain  deductions and credits claimed by the Company on its federal income tax
returns for the years 1981 through 1989.  The Revenue  Agents'  Reports  reflect
proposed adjustments to the Company's federal income tax returns for this period
which, if sustained,  would give rise to tax deficiencies totaling approximately
$227  million.  The  Company  believes  that any such  deficiencies  as  finally
determined would be significantly  less than the amounts proposed in the Revenue
Agents'  Reports.  The Revenue  Agents have also proposed  investment tax credit
(ITC)  adjustments  which, if sustained,  would reduce the ITC  carryforwards by
approximately  $96  million.  The Company  has  protested  some of the  proposed
adjustments  which are presently under review by the Regional  Appeals Office of
the  Internal  Revenue  Service.  If this review does not result in a settlement
that is  satisfactory  to the  Company,  the Company  intends to seek a judicial
review.  The Company  believes  that its  reserves are adequate to cover any tax
deficiency  that may ultimately be determined and that cash from operations will
be sufficient to satisfy any settlement reached.

The Company will exhaust its net operating loss  carryforwards  for  alternative
minimum tax purposes in 1996. As a result,  it is  anticipated  that the Company
will be required to pay approximately $80 million of alternative  minimum tax in
1996.  In addition,  during 1996,  the Company  anticipates  utilization  of net
operating  loss  carryforwards  amounting to  approximately  $547 million and to
fully utilize its remaining NOL for regular income tax purposes in 1997.


                                       44
<PAGE>



CAPITALIZATION

The Company's capitalization, including current maturities of long-term debt and
current  redemption  requirements  of preferred  stock, at December 31, 1995 and
1994,  was  $8.3  billion.   At  December  31,  1995  and  1994,  the  Company's
capitalization ratios were as follows:

                                                 1995           1994
                                                ------         -----
         Long-term debt                          61.8%          62.5%
         Preferred stock                          8.6            8.6
         Common shareowners' equity              29.6           28.9
                                                ------         -----
                                                100.0%         100.0%
                                                ======         ======


In support  of the  Company's  continuing  goal to reduce  its debt  ratio,  the
Company,  in 1995, retired at maturity,  with cash on hand, $25 million of First
Mortgage Bonds and  voluntarily  redeemed  prior to maturity,  the remaining $75
million of First Mortgage Bonds.  With the  retirement/  redemption of the First
Mortgage  Bonds,  the lien of the First  Mortgage  was  discharged  leaving  the
Company's  General  and  Refunding  Bonds  (G&R  Bonds) as its only  outstanding
secured indebtedness. The Company currently anticipates that it will use cash on
hand to satisfy the $415 million of G&R Bonds  scheduled  to mature in 1996.  At
such time, assuming a level of earnings consistent with 1995, the Company's debt
ratio will be below 60%.

During  1995,  the  Company  received  proceeds  from the sale of $50 million of
Electric  Facilities Revenue Bonds (EFRBs) issued by NYSERDA.  The proceeds from
this  offering  were used to  reimburse  the  Company's  treasury  for  electric
projects previously completed or under construction.


INVESTMENT RATING

The Company's  securities  are rated by Standard and Poor's  Corporation  (S&P),
Moody's Investors Service (Moody's),  Fitch Investors Service,  L.P. (Fitch) and
Duff and Phelps, Inc. (D&P). The rating agencies have been watching the electric
utility  industry  closely and have expressed  concern  regarding the ability of
high cost utilities, such as the Company, to recover all of their fixed costs in
a  competitive,  deregulated  marketplace.  

In 1995, Fitch lowered its credit ratings of the Company's securities one level.
Both Fitch and S&P have placed the Company's  securities on "Credit  Watch" with
"evolving or developing" implications. Credit Watch indicates a rating change is
likely, and the evolving or developing status indicates ratings may be raised or
lowered. Moody's continues to keep the Company's credit ratings under review for
a possible downgrade.


                                       45
<PAGE>




Currently, only the Company's G&R Bonds meet or exceed minimum investment grade.
At December 31, 1995, the ratings for each of the Company's principal securities
were as follows:


                                    S&P       Moody's     Fitch     D&P

         o   G&R Bonds               BBB-       Baa3       BBB-     BBB

         o   Debentures              BB+        Ba1        BB+      BB+

         o   Preferred Stock         BB+        ba1        BB+      BB

         o   Minimum Investment
              Grade                  BBB-       Baa3       BBB-    BBB-


CAPITAL REQUIREMENTS AND CAPITAL PROVIDED

Capital requirements and capital provided for 1995 and 1994 were as follows:

                                                       (In millions of dollars)
                                                       1995              1994

CAPITAL REQUIREMENTS
Construction*
    Electric                                         $  144           $   135
    Gas                                                  79               119
    Common                                               21                23
Total Construction                                      244               277
Refundings and Dividends
    Long-term debt                                      100               635
    Preferred stock                                       5                 5
    Common stock dividends                              211               205
    Preferred stock dividends                            53                53
    Redemption costs                                      -                 2
Total Refundings and Dividends                          369               900
Shoreham post-settlement costs                           71               167
TOTAL CAPITAL REQUIREMENTS                           $  684           $ 1,344

CAPITAL PROVIDED
Cash generated from operations                       $  772         $     836
Long-term debt issued                                    49               331
Common stock issued                                      20               118
Financing costs                                           -                (4)
Other investing activities                                9                 -
(Increase) decrease in cash                            (166)               63
TOTAL CAPITAL PROVIDED                               $  684           $ 1,344
* Excludes non-cash allowance for other funds used during
  construction.
For further information, see the Statement of Cash Flows.



                                       46
<PAGE>



Based upon the  availability of electricity  provided by the Company's  existing
generating  facilities,  including its portion of energy  generated at Nine Mile
Nuclear Power Station, Unit 2 (NMP2), and by its ability to purchase power under
firm  contracts  from other  electric  systems  and  certain  non-Company  owned
facilities located within the Company's service territory,  the Company believes
it has adequate  generating  resources  to meet its energy  demands for the next
several years.

For 1996,  total capital  requirements  (excluding  common stock  dividends) are
estimated at $792 million, of which maturing debt is $415 million,  construction
requirements  is $270  million,  preferred  stock  dividends  are  $52  million,
preferred stock sinking funds are $5 million and Shoreham  post-settlement costs
are $50  million  (including  $49 million  for  payments-in-lieu-of-taxes).  The
Company  believes that cash generated  from  operations and cash on hand will be
sufficient to meet all capital requirements in 1996.

RATE MATTERS

ELECTRIC

In 1993,  the Company  filed an  Electric  Rate Plan (Plan) with the PSC for the
three-year  period which began December 1, 1994. The goals of this Plan included
minimizing  future  electric  rate  increases in addition to  providing  for the
continued   recovery  of  the  Company's   regulatory   assets  while  retaining
consistency  with the Rate Moderation  Agreement's  (RMA) objective of restoring
the Company to financial health. As a result of the rate proceeding initiated by
the  filing of the  Company's  Plan,  the PSC  issued an Order for the rate year
beginning December 1, 1994. The Order,  which among other things,  froze overall
electric rates, reduced the Company's allowed return on common equity from 11.6%
to 11.0% and modified or eliminated certain performance-based incentives.

In addition,  the PSC ordered that the rate proceeding be continued to allow the
parties  to  develop  a plan  for  achieving  long-term  rate  stability  at the
prevailing rate levels, while, among other things,  providing for the continuing
recovery  of  the  Shoreham-related  assets.  In  its  rate  decision,  the  PSC
reaffirmed its  commitment to allow the Company to recover its  Shoreham-related
assets,  noting that it is a crucial factor in the Company's ability to maintain
its investment grade bond rating and to secure  reasonably  priced capital.  The
continuation  of the rate  proceeding  will also enable the PSC to consider  the
Company's  operations and its  opportunities to achieve greater  efficiency over
the next several years.

The Company filed a compliance filing under the terms of the Order to extend the
overall rate freeze  through the rate year which began December 1, 1995. The PSC
has yet to issue an electric rate order in response to this filing.

In  February  1996,  the PSC  issued  an order to show  cause and  instituted  a
proceeding to examine  various  opportunities  to reduce the  Company's  current
electric rates. Specifically, the Company has been directed to address the


                                       47
<PAGE>
                  


following:  (i) should all or a part of the $81 million  Suffolk County property
tax refund, as more fully discussed under the captions "Liquidity" and "Shoreham
Related Litigation",  be used to reduce current rates; (ii) should the return of
the $26 million 1995 rate year net reconciliation  credit to customers,  as more
fully  discussed in Note 3 of Notes to  Financial  Statements,  be  accelerated;
(iii)  determine,  upon review of the forecasts  reflected in the September 1995
compliance  filing  for the rate  year  commencing  December  1,  1995,  whether
adjustments to the forecasts can be reflected in rate reductions currently;  and
(iv) revisit the current  mechanics of the Fuel Cost Adjustment (FCA) clause, as
more  fully  discussed  in Notes 1 and 3 of Notes to  Financial  Statements,  to
determine  whether all or a portion of any fuel cost savings can be reflected in
current customer bills.

The  Company  has been  directed to submit a response to the order to show cause
addressing  these items.  Interested  parties will have an opportunity to submit
comments on the Company's  filing,  after which a hearing  before an ALJ will be
convened and the ALJ will determine further procedures. The Company is unable to
predict the outcome of this proceeding and the impact,  if any, that it may have
on the Company's cash flow, financial condition or results of its operations.

While no  assurance  can be given,  the  Company's  objective is to continue the
current rate freeze through the rate year ending November 30, 1997.

For a  further  discussion  respecting  electric  rates  see  Note 3 of Notes to
Financial Statements.

GAS

In December 1993, the PSC approved a three-year gas rate settlement  between the
Company  and the Staff of the PSC.  The gas rate  settlement  provides  that the
Company receive, for each of the rate years beginning December 1, 1993, 1994 and
1995,  annual gas rate increases of 4.7%,  3.8% and 3.2%,  respectively.  In the
determination  of the  revenue  requirements  for the gas  rate  settlement,  an
allowed  return on common  equity of 10.1% was used.  The gas rate decision also
provides  that  earnings in excess of a 10.6% return on common  equity be shared
equally  between the Company's  firm gas customers  and its  shareowners.  For a
further  discussion  respecting  gas  rates  see Note 3 of  Notes  to  Financial
Statements.

ENVIRONMENT

The Company is subject to federal,  state and local laws and regulations dealing
with  air and  water  quality  and  other  environmental  matters.  The  Company
continually  monitors its  activities  in order to determine  the impact of such
activities  on  the   environment   and  to  ensure   compliance   with  various
environmental laws. Except as set forth below, no material proceedings have been
commenced  or, to the  knowledge of the Company,  are  contemplated  against the
Company  with  respect  to  any  matter   relating  to  the  protection  of  the
environment.


                                       48
<PAGE>



The New  York  State  Department  of  Environmental  Conservation  (NYSDEC)  has
required  the Company and other New York State  utilities  to  investigate  and,
where  necessary,  remediate  their former  manufactured  gas plant (MGP) sites.
Currently,  the  Company  is the owner of six  pieces of  property  on which the
Company or certain of its  predecessor  companies  is believed to have  produced
manufactured  gas. The Company expects to enter into an  Administrative  Consent
Order (ACO) with the NYDEC in 1996  regarding the  management  of  environmental
activities  at these  properties.  Although  the exact  amount of the  Company's
clean-up costs cannot yet be determined, based on the findings of investigations
at two of these six  sites,  preliminary  estimates  indicate  that it will cost
approximately  $35  million to clean up all of these sites over the next five to
ten years.  Accordingly,  the Company had recorded a $35 million liability and a
corresponding  regulatory  asset to reflect its belief that the PSC will provide
for the future  recovery  of these costs  through  rates as it has for other New
York State utilities.  The Company has notified its former and current insurance
carriers that it seeks to recover from them certain of these  investigation  and
clean-up  costs.  However,  the  Company  is unable  to  predict  the  amount of
insurance recovery,  if any, that it may obtain. In addition,  there are several
other sites within the Company's  service  territory that were former MGP sites.
Research is underway to determine their relationship,  if any, to the Company or
its predecessor companies. Operations at these facilities in the late 1800's and
early  1900's may have  resulted in the  disposal of certain  waste  products on
these sites.

The Company has been notified by the Environmental  Protection Agency (EPA) that
it is one of many potentially  responsible parties (PRPs) that may be liable for
the remediation of three licensed treatment, storage and disposal sites to which
the Company may have shipped waste products and which have  subsequently  become
environmentally   contaminated.   At  one   site,   located   in   Philadelphia,
Pennsylvania,  and operated by Metal Bank of America, the Company and nine other
PRPs, all of which are public  utilities,  have entered into an ACO with the EPA
to conduct a Remedial  Investigation and Feasibility Study (RI/FS).  Under a PRP
participant  agreement,  the  Company  is  responsible  for  8.2%  of the  costs
associated  with this RI/FS  which has been  completed  and is  currently  being
reviewed by the EPA. The Company's total share of costs to date is approximately
$0.5 million.  The level of remediation required will be determined when the EPA
issues  its  decision.  Based on  information  available  to date,  the  Company
currently anticipates that the total cost to remediate this site will be between
$14  million and $30  million.  The  Company  has  recorded a liability  of $1.1
million  representing  its estimated  share of the additional  cost to remediate
this site.

With respect to the other two sites,  located in Kansas City,  Kansas and Kansas
City,  Missouri,  the  Company  is  investigating  allegations  that it had made
agreements for disposal of polychlorinated  biphenyls (PCBs) or items containing
PCBs at these sites. The EPA has provided the Company with documents  indicating
that the Company  was  responsible  for less than 1% of the total  weight of the
PCB-containing  equipment,  oil and materials  that were shipped to the Missouri
site. The EPA has not yet completed compiling documents for the Kansas site. The
Company is  currently  unable to  determine  its share,  if any,  of the cost to
remediate  these two sites or the  impact,  if any, on the  Company's  financial
position.


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<PAGE>



In addition,  the Company was notified  that it is a PRP at a Superfund  Site in
Farmingdale,  New York.  Portions of the site are  allegedly  contaminated  with
PCBs,  solvents and metals.  The Company was also notified by other PRPs that it
should be responsible for expenses in the amount of  approximately  $0.1 million
associated with removing PCB-contaminated soils from a portion of the site which
formerly  contained  electric  transformers.  The Company is currently unable to
determine its share of the cost to remediate this site or the impact, if any, on
the Company's financial position.

The Connecticut  Department of  Environmental  Protection  (DEP) and the Company
have  signed an ACO which will  require  the  Company  to address  leaks from an
electric  transmission  cable located under the Long Island Sound (Sound Cable).
The Sound Cable is jointly  owned by the Company and the  Connecticut  Light and
Power  Company,  a subsidiary of Northeast  Utilities.  Specifically,  the order
requires the Company to evaluate  existing  procedures  and  practices for cable
maintenance,  operations  and fluid  spill  response  procedures  and to propose
alternatives  to  minimize  fluid  spill  occurrences  and  their  impact on the
environment.   Alternatives  to  be  evaluated  range  from  improving  existing
monitoring  and  maintenance  practices to removal and  replacement of the Sound
Cable.  The Company is currently  unable to determine the costs it will incur to
complete  the  requirements  of the ACO or to  comply  with any  additional  DEP
requirements.

In addition,  the Company has been served with a subpoena from the U.S. Attorney
for the District of Connecticut to supply certain written information  regarding
releases of fluid from the Sound  Cable,  as well as  associated  operating  and
maintenance practices. Since the investigation is in its preliminary stages, the
Company is unable to determine  the  likelihood of a criminal  proceeding  being
initiated at this time. However, the Company believes all activities  associated
with the response to releases  from the Sound Cable were  consistent  with legal
and regulatory requirements.

The  Company  believes  that all  significant  costs  incurred  with  respect to
environmental  investigations  and  remediation  activities  will be recoverable
through rates.

CONSERVATION SERVICES

The Company's 1995 Demand Side Management  (DSM) Plan (1995 DSM Plan) focused on
promoting  energy  efficient  load  growth  while  minimizing  the  impact  that
conservation  programs have on increasing the Company's electric rates. The 1995
DSM Plan  reflected the Company's  goal to educate its customers on the benefits
of energy  efficiency  while  reducing the reliance on cash  subsidies.  The PSC
approved funding for the Company's 1995 DSM Plan at $12 million,  as compared to
$19 million and $33 million in 1994 and 1993, respectively. In addition, the PSC
established an incremental annualized energy savings goal of 70 Gwh, including a
monetary  penalty to the Company if 80% of the threshold  was not achieved.  The
Company was successful in exceeding the penalty threshold identified by the PSC.

In 1996, the Company plans to continue its pursuit of energy efficiency and peak
load reduction while maintaining the strategy of controlling electric

                                       50
<PAGE>



rates.  Through  careful  management  of DSM  expenditures  and the  delivery of
targeted DSM programs,  the Company plans to offer  cost-effective  DSM programs
that will appeal to a variety of  customers.  The 1996 DSM Plan will continue to
focus on customer education and information and to promote efficient load growth
in both the residential and commercial  sectors.  In addition,  the Company will
place an  increased  emphasis  on  programs  which  facilitate  the  attraction,
expansion and retention of major commercial/industrial customers. These programs
will act to position the Company as a business  partner,  helping to improve the
economic  climate on Long Island.  At the same time, these programs will help to
improve the Company's competitiveness as an energy provider.

SHOREHAM RELATED LITIGATION

Pursuant to the LIPA Act,  LIPA is  required  to make  payments-in-lieu-of-taxes
(PILOTs) to the  municipalities  that impose real  property  taxes on  Shoreham.
Pursuant to the 1989 Settlement, the Company agreed to fund LIPA's obligation to
make Shoreham  PILOTs.  The timing and duration of PILOTs under the LIPA Act are
the  subject  of  litigation  brought  in Nassau  County  Supreme  Court by LIPA
against,   among  others,  Suffolk  County,  the  Town  of  Brookhaven  and  the
Shoreham-Wading  River  Central  School  District.  The Company was permitted to
intervene in the lawsuit.  On January 10, 1994, the Appellate  Division,  Second
Department,  affirmed a lower court's March 29, 1993 decision holding,  in major
part, that the Company is not obligated for any real property taxes that accrued
after February 28, 1992, attributable to property that it conveyed to LIPA, that
PILOTs  commenced on March 1, 1992,  that PILOTs are subject to refunds and that
the LIPA act does not provide for the  termination of PILOTs.  Generally,  these
holdings are  favorable to the Company.  In October  1995,  the Court of Appeals
granted  the  parties  motion  for leave to  appeal  the  lower  court  decision
following an agreement  between the parties to voluntarily  dismiss  outstanding
causes of action.  The proper  amount of PILOTs is to be  determined  in pending
litigation described below.

The costs of Shoreham included real property taxes imposed by, among others, the
Town  of  Brookhaven  on  Shoreham  and   capitalized   by  the  Company  during
construction.  The Company had sought judicial review in New York Supreme Court,
Suffolk  County of the  assessments  upon which  those  taxes were based for the
years 1976 through 1992 (excluding  1979).  The Supreme Court  consolidated  the
review of the tax years at issue into two phases:  1976 through 1983,  excluding
1979,  which had been  settled  (Phase I); and 1984  through 1992 (Phase II). In
October 1992, the Supreme Court ruled that Shoreham had been overvalued for real
property tax  purposes  for Phase I. In May 1995,  the New York Court of Appeals
denied the request of the Town of Brookhaven and other  respondents for leave to
appeal  this  decision,  which  had been  previously  affirmed  in an  unanimous
decision  by  the  New  York  State  Appellate   Division,   Second  Department.
Thereafter,  in January 1996, the Company  received  approximately  $81 million,
including interest, from Suffolk County pursuant to this Phase I judgment.

In the Phase II proceeding, the Company is seeking to recover over $500 million,
plus interest,  in property taxes paid on Shoreham for the years  1984-1992.  In
this proceeding, the taking of evidence has been completed and final briefs have
been filed by the parties. The amount of the


                                       51
<PAGE>



Company's  recovery,  if any, in the Phase II  proceeding  and the timing of all
refunds  cannot yet be  determined.  LIPA has been permitted to intervene in the
proceeding  for the  1991-92  tax year  which  under  the  Appellate  Division's
decision  discussed above,  will partially  establish  LIPA's PILOT  obligation.
Pursuant to the Appellate Division's decision,  LIPA's PILOT obligations will be
determined  either by  agreement  or in a separate  proceeding  challenging  the
Shoreham assessment for the 1992-93 tax year.




                                       52
<PAGE>



RESULTS OF OPERATIONS

EARNINGS

Earnings for the years 1995, 1994 and 1993 were as follows:

                 (In millions of dollars and shares except earnings per share)
                                     1995          1994           1993

Net income                        $ 303.3      $  301.8        $  296.6
Preferred stock dividend
  requirements                       52.6          53.0            56.1
Earnings for Common Stock         $ 250.7      $  248.8        $  240.5

Average common shares
  outstanding                       119.2         115.9           112.1
Earnings per Common Share         $  2.10      $   2.15        $   2.15

The  Company's  1995 earnings per common share were lower than 1994 earnings per
common share as a result of the PSC's  current  electric  rate order,  effective
December 1, 1994, that lowered the allowed return on common equity from 11.6% to
11.0% and modified certain performance-based  incentives.  These two actions had
the effect of  reducing  the  Company's  earnings  by 15 cents per common  share
compared  to the  previous  year.  The effects of the  electric  rate order were
mitigated by a significant reduction in operating costs which were achieved by a
comprehensive cost containment program.

Earnings per common share for the gas business were higher in 1995 when compared
to 1994 due to cost  containment  measures and a write-off in 1994 of previously
deferred  storm costs.  The higher  level of earnings in the gas  business  also
helped to mitigate the adverse effects of the electric rate order.

Earnings per common share for 1994 equaled that of 1993.  The electric  business
achieved a higher  level of earnings  which were offset by a decrease in the gas
business earnings.

REVENUES

Total revenues,  including  revenues from the recovery of fuel costs,  were $3.1
billion for each of the years ended December 31, 1995 and 1994, and $2.9 billion
for the year ended December 31, 1993.


Electric Revenues

Revenues from the  Company's  electric  operations  totaled $2.5 billion for the
years ended December 31, 1995 and 1994, compared to $2.4 billion in 1993.

The Company's electric rates have not increased since December 1, 1993, when the
Company  received an electric  rate  increase of 4.0%.  Given the absence of any
electric rate increases combined with operating in a mature

                                       53
<PAGE>



market, electric revenues have remained relatively flat over the last two years.
The December  1993 rate  increase  provided $69 million of  additional  electric
revenues in 1994 when compared to 1993.

For a  further  discussion  on  electric  rates,  see  Notes 1 and 3 of Notes to
Financial Statements.

Total electric  sales volumes were 16,572  million  kilowatt hour (kWh) in 1995,
16,382  million kWh in 1994 and 16,128 million kWh in 1993. The increase in 1995
sales  when  compared  to 1994 is  attributable  primarily  to higher  sales for
resale.  System sales for 1995, when compared to 1994, were negatively  impacted
by a 174 million kWh reduction in customer  usage due to the effects of weather.
Partially  offsetting  this  reduction  was a 116 million kWh increase in system
load over 1994.  The 116  million  kWh growth  occurred  despite the loss of the
Stony Brook  Project.  The increase in system sales for 1994,  when  compared to
1993, was primarily the result of warmer  weather  experienced in the comparable
summer  months.  In each of the years  1995,  1994 and 1993,  residential  sales
accounted for 45% of total system sales,  while  commercial and industrial sales
accounted for 52% of the total,  with sales to public  authorities  representing
3%.

Gas Revenues

Revenues  from the Company's gas  operations  for the years 1995,  1994 and 1993
were $591 million, $586 million and $529 million, respectively.

In December 1993, the PSC approved a three-year gas rate settlement  between the
Company and the Staff of the PSC. The gas rate  settlement  provided the Company
with  annual  gas  rate  increases  of 4.7%,  3.8%  and 3.2% for the rate  years
beginning  December 1, 1993, 1994 and 1995,  respectively.  These rate increases
provided $21 million in  additional  revenues for 1995 as compared to 1994,  and
$25 million in additional revenues for 1994 as compared to 1993.


A decrease  of $24  million in the  recoveries  of gas fuel  expenses  more than
offset the additional revenues provided by the annual gas rate increase in 1995.
The decrease in the recovery of gas fuel  expenses in 1995 was  primarily due to
lower  average gas prices  when  compared to 1994.  The  recoveries  of gas fuel
expenses in 1994 when compared to 1993,  increased by $33 million  primarily due
to increased billed sales volumes and higher average gas prices. The Company has
a  weather   normalization   clause  to  mitigate  the  impact  on  revenues  of
experiencing weather that is warmer or colder than normal.

In 1993, the Company began selling gas to businesses  off the Company's  system.
These  off-system  gas sales  revenues  totaled $24 million,  $26 million and $8
million for the years 1995, 1994 and 1993,  respectively.  Profits realized from
off-system sales are allocated 85% to firm gas customers and 15% to shareowners.

For 1995, firm gas sales volumes decreased by less than 1% when compared to 1994
even  though the 1995  heating  season  was much  warmer  than the 1994  heating
season. The impact of the warmer weather was ameliorated by the addition of over
6,500 new gas space heating customers during 1995,

                                       54
<PAGE>



resulting from the continuation of the Company's gas expansion program. In 1994,
the Company added over 7,000 gas space heating customers.

OPERATING EXPENSES

Fuel and Purchased Power

Fuel and  purchased  power  expenses  for the years 1995,  1994 and 1993 were as
follows:

                                           (In millions of dollars)
                                       1995         1994       1993

Fuel for Electric Operations
  Oil                                 $    98       $ 145       $ 180
  Gas                                     149         101          93
  Nuclear                                  14          15          13
  Purchased power                         310         308         293
Total                                     571         569         579
Gas fuel                                  264         279         249
Total                                 $   835       $ 848       $ 828


During 1995, the Company  refitted an additional steam generating unit to enable
it to burn either oil or natural  gas,  bringing the total number of steam units
capable of burning  natural gas to seven.  Of these seven,  five are dual-fired,
having the  capability of burning  either  natural gas or oil. As a result,  the
Company, over the past three years, has increased the amount of energy generated
with natural gas,  thereby  displacing more costly energy  generated with oil or
purchased from others.  Electric fuel expense for 1995  increased  slightly from
1994 as a result of increased electric sales volumes. For 1994, fuel expense for
electric generation decreased relative to 1993 as a result of an increase in the
amount of energy generated with more economical natural gas.

Electric fuel and purchased  power mix for the years 1995, 1994 and 1993 were as
follows:

                                            (In thousands of MWH)
                         1995                1994              1993
                      MWH     %          MWH      %        MWH       %
Oil                  3,099   17%        4,480    25%      5,894     34%
Gas                  6,344   36         4,056    23       3,329     19
Nuclear              1,301    7         1,498     9       1,291      7
Purchased power      7,143   40         7,640    43       7,023     40
Total               17,887  100%       17,674   100%     17,537    100%


The Company has reduced oil consumption by purchasing more economical power from
other systems, by increased generation with natural gas, by using energy


                                       55
<PAGE>
                                                                   


generated  at  NMP2  and by  purchasing  energy  supplied  by  cogenerators  and
independent  power producers (IPPs) as required by New York State law. The total
barrels of oil consumed for electric  operations were 5.2 million,  7.5 million,
and 9.7 million for the years 1995, 1994 and 1993, respectively.

Cogenerators  and IPPs  provided  approximately  10% of the  total  energy  made
available by the Company in 1995 and approximately 9% in both 1994 and 1993. The
increase in purchased power expenses in 1995 and 1994 is primarily  attributable
to purchases  from the 136 MW facility in Holtsville,  New York,  owned by NYPA,
and constructed for the benefit of the Company.

Gas system fuel  expenses  decreased in 1995 by $15 million when  compared  with
1994, despite higher sales volumes, because of a decline in the average price of
gas. In 1994,  these expenses  increased by $30 million when compared with 1993,
primarily due to the costs  associated  with the Company's  off-system gas sales
which began in 1993.

Operations and Maintenance Expenses

Operations and maintenance  (O&M) expenses,  excluding fuel and purchased power,
were $511 million,  $541 million and $522 million,  for the years 1995, 1994 and
1993,  respectively.  The  decrease  in O&M for  1995 was  primarily  due to the
continuation of the Company's cost  containment  efforts which resulted in lower
production  costs,   lower   transmission  and  distribution   costs  and  lower
administrative and general expenses.

O&M  expenses  increased in 1994 when  compared to 1993 due to the  write-off of
previously  deferred storm costs associated with gas operations,  an increase in
costs  associated with the Company's gas expansion  program,  the recognition of
certain costs which exceeded the Company's insurance recoveries, and an increase
in employee benefit costs.

Rate Moderation Component

The rate  moderation  component  reflects the  difference  between the Company's
revenue requirements under conventional  ratemaking and the revenues provided by
its  electric  rate  structure.  In 1995,  1994 and 1993,  the Company  recorded
non-cash  charges to income of approximately  $22 million,  $198 million and $89
million,  respectively,  representing  the amortization of the RMC. In 1995, the
operation of the Fuel Moderation Component (FMC) as discussed in Note 3 of Notes
to  Financial  Statements,  resulted in credits to the RMC of $87 million  which
more than offset the  accretion of the RMC  resulting  from  revenues  under the
current  electric  rate  structure  being less than revenue  requirements  under
conventional  ratemaking.  For the years 1994 and 1993,  revenues under the rate
structure  in  effect  in those  years,  were  greater  than  that  required  by
conventional  ratemaking  resulting in the amortization of the RMC. In addition,
the RMC  amortization  for the years 1994 and 1993  increased as a result of the
FMC, which totaled $83 million and $45 million for 1994 and 1993,  respectively.
For a  further  discussion  on  the  RMC,  see  Note  3 of  Notes  to  Financial
Statements.

Other Regulatory Amortization

In 1995, the net total of other regulatory amortization was a non-cash charge

                                       56
<PAGE>




to income of $161.6  million,  compared to $4.3 million in 1994.  This change is
primarily attributable to the operation of the revenue reconciliation  mechanism
and increased  amortization  of the LRPP  deferrals,  as more fully discussed in
Note 3 of Notes to Financial Statements.  The revenue reconciliation  mechanism,
as established under the LRPP, eliminates the impact on earnings of experiencing
electric sales that are above or below adjudicated  levels, by providing a fixed
annual  net  margin  level  (defined  as sales  revenue,  net of fuel and  gross
receipts  taxes).  The difference  between the actual and adjudicated net margin
sales level is deferred on a monthly  basis during the year.  During  1995,  the
Company  recorded  a  non-cash  charge to income of  approximately  $64  million
representing  a net margin  level in excess of that  provided  for in rates.  In
1994, the Company recorded  non-cash income of approximately  $51 million as the
actual net margin  level was below that  which was  provided  for in rates.  The
increase in the amortization of the LRPP deferrals in 1995 totaled $34 million.

In 1994, other  regulatory  amortization was higher than 1993 as a result of the
amortization  of the 1992 rate year LRPP  deferrals  which began in August 1993,
the operation of the interest deferral mechanism and an increase in amortization
expense related to Shoreham  post-settlement  costs.  These items were partially
offset by higher net margin revenues.

Operating Tax

Operating  tax were $448  million,  $407  million and $386 million for the years
1995,   1994  and  1993,   respectively.   The  increase  in  operating  tax  of
approximately   $41  million  in  1995  when   compared  to  1994  is  primarily
attributable to increased  property  taxes.  The increase of $21 million in 1994
when compared to 1993 is primarily  attributable  to higher gross receipts taxes
resulting from increased  revenues,  higher property taxes,  additional  payroll
taxes and higher dividend taxes.

Federal Income Taxes

Federal  income taxes were $206  million,  $177 million and $172 million for the
years 1995, 1994 and 1993, respectively. The increase in federal income taxes in
1995 when compared to 1994 is primarily  attributable to higher earnings and the
amortization of a tax rate increase which had previously been deferred.

INTEREST EXPENSE

The  reductions  in interest  expense in 1995 when  compared to 1994 and in 1994
when  compared to 1993 are  primarily  attributable  to lower  outstanding  debt
levels.  The Company's  strategy is to apply  available cash balances toward the
satisfaction  of debt whenever  practicable.  Accordingly,  in 1995, the Company
used approximately $75 million of cash on hand to redeem, prior to maturity, the
remaining  outstanding  First  Mortgage  Bonds.  During  1994,  the Company used
approximately $200 million of cash on hand and the proceeds from the issuance of
5.1 million shares of common stock to reduce debt levels by  approximately  $300
million.  The lower interest  expense in 1994 also reflects the  satisfaction of
$175  million of debt which  matured  in  November  1993 with the use of cash on
hand.


                                       57
<PAGE>




SELECTED FINANCIAL DATA

Additional information respecting revenues, expenses, electric and gas operating
income and operations data and balance sheet information for the last five years
is provided in Tables 1 through 11 of Selected Financial Data.  Information with
regard to the Company's  business  segments for the last three years is provided
in Note 11 of Notes to Financial Statements.


                                       58
<PAGE>




ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

<TABLE>
                                                                                      Page
<S>                                                                                   <C> 
Statement of Income for each of the three years in the period ended December
31, 1995.                                                                              60

Balance Sheet at December 31, 1995 and 1994.                                           61

Statement of Retained Earnings for each of the three years in the period
ended December 31, 1995.                                                               63

Statement of Capitalization at December 31, 1995 and 1994.                             63

Statement of Cash Flows for each of the three years in the period ended
December 31, 1995.                                                                     65

Notes to Financial Statements.                                                         66

Report of Independent Auditors.                                                       105

Financial Statement Schedules - The following Financial Statement
Schedule is submitted as part of Item 14, "Exhibits, Financial Statement
Schedules and Reports on Form 8-K," of this Annual Report. (All other
Financial Statement Schedules are omitted because they are not
applicable, or the required information appears in the Financial
Statements or the Notes thereto.

-Valuation and Qualifying Accounts (Schedule II)                                      114
</TABLE>


                                       59
<PAGE>
FINANCIAL STATEMENTS
BALANCE SHEET                                     
                                                       (In thousands of dollars)
ASSETS  at December 31                                  1995          1994

UTILITY PLANT
Electric                                         $   3,786,540   $ 3,657,178
Gas                                                  1,086,145       994,742
Common                                                 244,828       232,346
Construction work in progress                          100,521       129,824
Nuclear fuel in process and in reactor                  16,456        23,251
                                                     5,234,490     5,037,341
Less - Accumulated depreciation
  and amortization                                   1,639,492     1,538,995
Total Net Utility Plant                              3,594,998     3,498,346

REGULATORY ASSETS
Base financial component
  (less accumulated amortization
  of $656,311 and $555,340)                          3,382,519     3,483,490
Rate moderation component                              383,086       463,229
Shoreham post-settlement costs                         968,999       922,580
Shoreham nuclear fuel                                   71,244        73,371
Unamortized cost of issuing securities                 222,567       254,482
Postretirement benefits other than pensions            383,642       412,727
Regulatory tax asset                                 1,802,383     1,831,689
Other                                                  230,663       250,804
Total Regulatory Assets                              7,445,103     7,692,372

NONUTILITY PROPERTY AND OTHER INVESTMENTS               16,030        24,043

CURRENT ASSETS
Cash and cash equivalents                              351,453       185,451
Special deposits                                        63,412        27,614
Customer accounts receivable
  (less allowance for doubtful
  accounts of $24,676 and $23,365)                     282,218       245,125
LRPP receivable                                         69,558        54,512
Other accounts receivable                              107,387        14,030
Accrued unbilled revenues                              184,440       164,379
Materials and supplies at average cost                  63,595        74,777
Fuel oil at average cost                                32,090        37,723
Gas in storage at average cost                          53,076        68,447
Deferred tax asset                                     191,000       213,996
Prepayments and other current assets                     8,986         5,327
Total Current Assets                                 1,407,215     1,091,381

DEFERRED CHARGES                                        21,023       172,768

TOTAL ASSETS                                     $  12,484,369  $ 12,478,910

See Notes to Financial Statements.

                                       60

<PAGE>
                                                       (In thousands of dollars)
CAPITALIZATION AND LIABILITIES at December 31          1995            1994

CAPITALIZATION
Long-term debt                                   $  4,722,675     $ 5,162,675 
Unamortized discount on debt                          (16,075)        (17,278)
                                                    4,706,600       5,145,397

Preferred stock - redemption required                 639,550         644,350
Preferred stock - no redemption required               63,934          63,957
Total Preferred Stock                                 703,484         708,307

Common stock                                          598,277         592,083
Premium on capital stock                            1,114,508       1,101,240
Capital stock expense                                 (50,751)        (52,175)
Retained earnings                                     790,919         752,480
Total Common Shareowners' Equity                    2,452,953       2,393,628

Total Capitalization                                7,863,037       8,247,332

REGULATORY LIABILITIES
Regulatory liability component                        277,757         357,117
1989 Settlement credits                               136,655         145,868
Regulatory tax liability                              116,060         111,218
Other                                                 132,694         147,041
Total Regulatory Liabilities                          663,166         761,244

CURRENT LIABILITIES
Current maturities of long-term debt                  415,000          25,000
Current redemption requirements of preferred stock      4,800           4,800
Accounts payable and accrued expenses                 260,879         241,775
Accrued taxes (including federal income
  tax of $28,736 and $28,340)                          60,498          58,133
Accrued interest                                      158,325         149,929
Dividends payable                                      57,899          57,367
Class Settlement                                       45,833          35,833
Customer deposits                                      29,547          28,474
Total Current Liabilities                           1,032,781         601,311

DEFERRED CREDITS
Deferred federal income tax                         2,337,732       2,204,023
Class Settlement                                      129,809         151,604
Other                                                   8,708           9,774
Total Deferred Credits                              2,476,249       2,365,401

OPERATING RESERVES
Pensions and other postretirement benefits            396,490         453,016
Claims and damages                                     52,646          50,606
Total Operating Reserves                              449,136         503,622

COMMITMENTS AND CONTINGENCIES                               -               -

TOTAL CAPITALIZATION AND LIABILITIES             $ 12,484,369     $12,478,910

See Notes to Financial Statements.


                                       61
<PAGE>
<TABLE>
<CAPTION>

STATEMENT OF INCOME                                                         (In thousands of dollars except per share amounts)
For year ended December 31                                                  1995               1994                1993

REVENUES
<S>                                                                  <C>                 <C>                 <C>    
Electric                                                              $   2,484,014      $   2,481,637      $    2,352,109
Gas                                                                         591,114            585,670             528,886
Total Revenues                                                            3,075,128          3,067,307           2,880,995

OPERATING EXPENSES
Operations - fuel and purchased power                                       834,979            847,986             827,591
Operations - other                                                          383,238            406,014             387,808
Maintenance                                                                 128,155            134,640             133,852
Depreciation and amortization                                               145,357            130,664             122,471
Base financial component amortization                                       100,971            100,971             100,971
Rate moderation component amortization                                       21,933            197,656              88,667
Regulatory liability component amortization                                 (79,359)           (79,359)            (79,359)
1989 Settlement credits amortization                                         (9,214)            (9,214)             (9,214)
Other regulatory amortization                                               161,605              4,328             (18,044)
Operating taxes                                                             447,507            406,895             385,847
Federal income tax - current                                                 14,596             10,784               6,324
Federal income tax - deferred and other                                     193,742            170,997             178,530
Total Operating Expenses                                                  2,343,510          2,322,362           2,125,444
Operating Income                                                            731,618            744,945             755,551

OTHER INCOME AND (DEDUCTIONS)
Rate moderation component carrying charges                                   25,274             32,321              40,004
Other income and deductions, net                                             34,400             35,343              38,997
Class Settlement                                                            (21,669)           (22,730)            (23,178)
Allowance for other funds used during construction                            2,898              2,716               2,473
Federal income tax - deferred and other                                       2,800              5,069              12,578
Total Other Income and (Deductions)                                          43,703             52,719              70,874
Income Before Interest Charges                                              775,321            797,664             826,425

INTEREST CHARGES
Interest on long-term debt                                                  412,512            437,751             466,538
Other interest                                                               63,461             62,345              67,534
Allowance for borrowed funds used during construction                        (3,938)            (4,284)             (4,210)
Total Interest Charges                                                      472,035            495,812             529,862

NET INCOME                                                                  303,286            301,852             296,563
Preferred stock dividend requirements                                        52,620             53,020              56,108

EARNINGS FOR COMMON STOCK                                             $     250,666     $      248,832     $       240,455

AVERAGE COMMON SHARES OUTSTANDING (000)                                     119,195            115,880             112,057

EARNINGS PER COMMON SHARE                                             $        2.10     $         2.15     $          2.15

DIVIDENDS DECLARED PER COMMON SHARE                                   $        1.78     $         1.78     $          1.76

See Notes to Financial Statements.
</TABLE>


                                       62
<PAGE>
<TABLE>
<CAPTION>

       STATEMENT OF RETAINED EARNINGS                                        (In thousands of dollars)
                                                                      1995            1994          1993
    <S>                                                        <C>             <C>             <C>    
       Balance at January 1                                    $   752,480     $   711,432    $  667,988
       Net income for the year                                     303,286         301,852       296,563
                                                                 1,055,766       1,013,284       964,551
       Deductions
       Cash dividends declared on common stock                     212,181         207,794       197,236
       Cash dividends declared on preferred stock                   52,647          53,046        55,861
       Other                                                            19             (36)           22
       BALANCE AT DECEMBER 31                                  $   790,919     $   752,480    $  711,432

       See Notes to Financial Statements.
</TABLE>

<TABLE>
<CAPTION>

       STATEMENT OF CAPITALIZATION                           Shares Outstanding           (In thousands of dollars)
       At December 31                                       1995             1994          1995             1994

       COMMON SHAREOWNERS' EQUITY
       <S>                                           <C>              <C>            <C>              <C> 
       Common stock, $5.00 par value                 119,655,441      118,416,606     $   598,277    $     592,083
       Premium on capital stock                                                         1,114,508        1,101,240
       Capital stock expense                                                              (50,751)         (52,175)
       Retained earnings                                                                  790,919          752,480
       TOTAL COMMON SHAREOWNERS' EQUITY                                                 2,452,953        2,393,628

       PREFERRED STOCK - REDEMPTION REQUIRED
       Par value $100 per share
             7.40% Series L                              171,500          182,000          17,150           18,200
             8.50% Series R                               37,500           75,000           3,750            7,500
             7.66% Series CC                             570,000          570,000          57,000           57,000
       Less - Sinking fund requirement                                                      4,800            4,800
                                                                                           73,100           77,900
       Par value $25 per share
             7.95% Series AA                          14,520,000       14,520,000         363,000          363,000
             $1.67 Series GG                             880,000          880,000          22,000           22,000
             $1.95 Series NN                           1,554,000        1,554,000          38,850           38,850
             7.05% Series QQ                           3,464,000        3,464,000          86,600           86,600
             6.875% Series UU                          2,240,000        2,240,000          56,000           56,000
                                                                                          566,450          566,450
       Total Preferred Stock - Redemption Required                                        639,550          644,350

       PREFERRED STOCK - NO REDEMPTION REQUIRED
       Par value $100 per share
             5.00% Series B                              100,000          100,000          10,000           10,000
             4.25% Series D                               70,000           70,000           7,000            7,000
             4.35% Series E                              200,000          200,000          20,000           20,000
             4.35% Series F                               50,000           50,000           5,000            5,000
             5 1/8% Series H                             200,000          200,000          20,000           20,000
             5 3/4% Series I -  Convertible               19,336           19,569           1,934            1,957
       Total Preferred Stock - No Redemption Required                                      63,934           63,957
       TOTAL PREFERRED STOCK                                                          $   703,484    $     708,307

       See Notes to Financial Statements.
</TABLE>

                                       63
<PAGE>
<TABLE>
<CAPTION>
                                                                                                           (In thousands of dollars)
       At December 31                             Maturity           Interest Rate    Series         1995         1994
       FIRST MORTGAGE BONDS
                                                 <S>                <C>               <C>      <C>           <C>       
                                                   June 1, 1995        4.55%           O       $ -           $   25,000
                                                  March 1, 1996        5 1/4%          P            -            40,000
                                                  April 1, 1997        5 1/2%          Q            -            35,000
       Total First Mortgage Bonds                                                                   -           100,000

       GENERAL AND REFUNDING BONDS
                                                    May 1, 1996        8 3/4%                     415,000        415,000
                                              February 15, 1997        8 3/4%                     250,000        250,000
                                                 April 15, 1998        7 5/8%                     100,000        100,000
                                                   May 15, 1999        7.85%                       56,000         56,000
                                                 April 15, 2004        8 5/8%                     185,000        185,000
                                                   May 15, 2006        8.50%                       75,000         75,000
                                                  July 15, 2008        7.90%                       80,000         80,000
                                                    May 1, 2021        9 3/4%                     415,000        415,000
                                                   July 1, 2024        9 5/8%                     375,000        375,000
       Total General and Refunding Bonds                                                        1,951,000      1,951,000
       DEBENTURES
                                                  July 15, 1999        7.30%                      397,000        397,000
                                               January 15, 2000        7.30%                       36,000         36,000
                                                  July 15, 2001        6.25%                      145,000        145,000
                                                 March 15, 2003        7.05%                      150,000        150,000
                                                  March 1, 2004        7.00%                       59,000         59,000
                                                   June 1, 2005        7.125%                     200,000        200,000
                                                  March 1, 2007        7.50%                      142,000        142,000
                                                  July 15, 2019        8.90%                      420,000        420,000
                                               November 1, 2022        9.00%                      451,000        451,000
                                                 March 15, 2023        8.20%                      270,000        270,000
       Total Debentures                                                                         2,270,000      2,270,000
       AUTHORITY FINANCING NOTES
       Industrial Development Revenue Bonds
                                               December 1, 2006        7.50%          1976 A,B      2,000          2,000
       Pollution Control Revenue Bonds
                                               December 1, 2006        7.50%          1976 A       28,375         28,375
                                               December 1, 2009        7.80%          1979 B       19,100         19,100
                                                October 1, 2012        8 1/4%         1982         17,200         17,200
                                                  March 1, 2016        4.70%          1985 A,B    150,000        150,000
       Electric Facilities Revenue Bonds
                                              September 1, 2019        7.15%          1989 A,B    100,000        100,000
                                                   June 1, 2020        7.15%          1990 A      100,000        100,000
                                               December 1, 2020        7.15%          1991 A      100,000        100,000
                                               February 1, 2022        7.15%          1992 A,B    100,000        100,000
                                                 August 1, 2022        6.90%          1992 C,D    100,000        100,000
                                               November 1, 2023        5.00%          1993 A       50,000         50,000
                                               November 1, 2023        5.05%          1993 B       50,000         50,000
                                                October 1, 2024        4.95%          1994 A       50,000         50,000
                                                 August 1, 2025        5.00%          1995 A       50,000              -
       Total Authority Financing Notes                                                            916,675        866,675
       Unamortized Discount on Debt                                                               (16,075)       (17,278)
       Total                                                                                    5,121,600      5,170,397
       Less Current Maturities                                                                    415,000         25,000
       TOTAL LONG-TERM DEBT                                                                     4,706,600      5,145,397
       TOTAL CAPITALIZATION                                                                    $7,863,037    $ 8,247,332

       See Notes to Financial Statements.
</TABLE>
       
                                       64
<PAGE>
<TABLE>
<CAPTION>


STATEMENT OF CASH FLOWS                                                           (In thousands of dollars)
For year ended December 31                                             1995           1994             1993
OPERATING ACTIVITIES
<S>                                                            <C>              <C>            <C>
Net Income                                                      $    303,286    $   301,852    $     296,563
Adjustments to reconcile net income to net
   cash provided by operating activities
  Depreciation and amortization                                      145,357        130,664          122,471
  Base financial component amortization                              100,971        100,971          100,971
  Rate moderation component amortization                              21,933        197,656           88,667
  Regulatory liability component amortization                        (79,359)       (79,359)         (79,359)
  1989 Settlement credits amortization                                (9,214)        (9,214)          (9,214)
  Other regulatory amortization                                      161,605          4,328          (18,044)
  Rate moderation component carrying charges                         (25,274)       (32,321)         (40,004)
  Amortization of cost of issuing and redeeming securities            39,589         46,237           52,063
  Class Settlement                                                    21,669         22,730           23,178
  Provision for doubtful accounts                                     17,751         19,542           18,555
  Federal income tax - deferred and other                            190,942        165,928          165,952
  Other                                                               61,576         46,531            9,228
Changes in operating assets and liabilities
  Accounts receivable                                                (67,213)       (17,353)         (65,898)
  Class Settlement                                                   (33,464)       (30,235)         (25,302)
  Accrued unbilled revenues                                          (20,061)         5,663          (26,870)
  Accounts payable and accrued expenses                               19,100        (44,598)          (8,800)
  Other                                                              (77,194)         6,727          (22,144)
Net Cash Provided by Operating Activities                            772,000        835,749          582,013

INVESTING ACTIVITIES

Construction and nuclear fuel expenditures                          (243,586)      (276,954)        (302,220)
Shoreham post-settlement costs                                       (70,589)      (167,367)        (207,114)
Other investing activities                                             8,019         (1,349)            (934)
Net Cash Used in Investing Activities                               (306,156)      (445,670)        (510,268)

FINANCING ACTIVITIES

Proceeds from issuance of securities                                  68,726        449,434        1,305,802
Redemption of securities                                            (104,800)      (639,858)      (1,165,600)
Common stock dividends paid                                         (211,630)      (205,086)        (195,794)
Preferred stock dividends paid                                       (52,667)       (52,927)         (56,727)
Other financing activities                                               529         (4,723)         (20,379)
Net Cash Used in Financing Activities                               (299,842)      (453,160)        (132,698)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS           $     166,002    $   (63,081)   $     (60,953)
Cash and cash equivalents at January 1                         $     185,451    $   248,532    $     309,485
Net increase (decrease) in cash and cash equivalents                 166,002        (63,081)         (60,953)
CASH AND CASH EQUIVALENTS AT DECEMBER 31                       $     351,453    $   185,451    $     248,532


Interest paid, before reduction for the allowance
   for borrowed funds used during constuction                  $     427,988    $   446,340    $     469,978
Federal income tax - paid                                      $      14,200    $    10,780    $       6,000
Federal income tax - refunded                                  $           -    $         -    $       1,000

See Notes to Financial Statements.

</TABLE>
                                       65
<PAGE>

NOTES TO FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

Long Island  Lighting  Company (the Company) was  incorporated in 1910 under the
Transportation  Corporations Law of the State of New York and supplies  electric
and gas service in Nassau and Suffolk Counties and to the Rockaway  Peninsula in
Queens County,  all on Long Island,  New York. The Company's  service  territory
covers an area of  approximately  1,230  square  miles.  The  population  of the
service area,  according to the Company's  1995  estimate,  is about 2.7 million
persons,  including  approximately  98,000  persons who reside in Queens  County
within the City of New York.

The  Company  serves   approximately  1  million  electric  customers  of  which
approximately 915,000 are residential. The Company receives approximately 49% of
its  electric  revenues  from  residential   customers,   48%  from  commercial/
industrial  customers  and the balance from sales to other  utilities and public
authorities.  The Company  also  serves  approximately  453,000  gas  customers,
408,000 of which are residential,  accounting for 62% of the gas revenues,  with
the balance of the gas revenues  made up by the  commercial/industrial  customer
class.

The Company  believes that its current  customer  base is stable.  The Company's
geographic  location and the limited electrical  interconnections to Long Island
serve  to  limit  the  accessibility  of  the  transmission  grid  to  potential
competitors  from off the system.  In addition,  the Company does not expect any
new major independent power producers (IPPs) or cogenerators to be built on Long
Island in the foreseeable  future. One of the reasons supporting this conclusion
is based on the Company's  belief that the composition  and  distribution of the
Company's remaining  commercial and industrial customers would make it difficult
for large electric projects to operate economically.  Furthermore, under federal
law,  the  Company is required to buy energy  from  qualified  producers  at the
Company's  avoided  cost.  Current  long-range  avoided cost  estimates  for the
Company  have  significantly  reduced the economic  advantage  to  entrepreneurs
seeking to compete with the Company and with existing IPPs.

REGULATION

The Company's  accounting  records are maintained in accordance with the Uniform
Systems of Accounts  prescribed by the Public Service Commission of the State of
New  York  (PSC)  and the  Federal  Energy  Regulatory  Commission  (FERC).  Its
financial  statements  reflect  the  ratemaking  policies  and  actions of these
commissions in conformity  with  generally  accepted  accounting  principles for
rate-regulated enterprises.

ACCOUNTING FOR THE EFFECTS OF RATE REGULATION

GENERAL

The Company is subject to the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of

                                       66

<PAGE>



Regulation".  This  statement  recognizes  the economic  ability of  regulators,
through  the  ratemaking   process,  to  create  future  economic  benefits  and
obligations affecting rate-regulated companies. The Company records these future
economic benefits and obligations as regulatory assets and liabilities.

Regulatory assets represent  probable future revenues to the Company  associated
with previously incurred costs that are expected to be recovered from customers.
Regulatory   liabilities   represent  probable  future  reductions  in  revenues
associated  with amounts  that are expected to be refunded to customers  through
the ratemaking process. Regulatory assets net of regulatory liabilities amounted
to  approximately  $6.8  billion and $6.9 billion at December 31, 1995 and 1994,
respectively.

In order for a rate-regulated entity to continue to apply the provisions of SFAS
No.  71,  it must  continue  to  meet  the  following  three  criteria:  (i) the
enterprise's  rates for regulated  services  provided to its  customers  must be
established by an independent  third-party  regulator;  (ii) the regulated rates
must be designed to recover the specific  enterprise's  costs of  providing  the
regulated  services;  and (iii) in view of the demand for the regulated services
and the level of  competition,  it is  reasonable  to assume  that  rates set at
levels that will recover the enterprise's  costs can be charged to and collected
from customers.

Based upon the Company's  evaluation of the three  criteria  discussed  above in
relation to its operations,  the effect of competition on its ability to recover
its costs,  including  its allowed  return on common  equity and the  regulatory
environment in which the Company operates, the Company believes that SFAS No. 71
continues to apply to the  Company's  electric and gas  operations.  The Company
formed its conclusion  based upon several factors  including:  (i) the Company's
continuing  ability  to earn its  allowed  return on common  equity for both its
electric and gas  operations;  and (ii) the PSC's  continued  affirmation of its
commitment to the Company's full recovery of the Shoreham  Nuclear Power Station
(Shoreham) related assets and all other prudently incurred costs.

Notwithstanding  the above, rate regulation is undergoing  significant change as
regulators  and  customers  seek lower prices for  electric and gas service.  As
discussed more fully in Note 10, the PSC has initiated Competitive Opportunities
Proceedings  seeking ways to  transition  the  electric  industry to full retail
competition, the outcome of which could result in significant changes in the way
the  Company  will be  regulated  in the  future.  In the event that  regulation
significantly  changes the  opportunity  for the Company to recover its costs in
the future, all or a portion of the Company's  operations may no longer meet the
criteria  discussed  above.  In that  event,  all or a portion of the  Company's
existing regulatory assets and liabilities would be written-off.  For additional
information respecting the Company's Shoreham-related assets, see Note 10.

Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
which amends SFAS No. 71.  Under SFAS No. 121, costs which were capitalized,
because it was probable that future recovery would be allowed by the regulator,
must be charged against current period earnings if it appears

                                       67

<PAGE>



that the criterion for capitalization no longer applies.  The carrying amount
of the asset would be reduced by disallowed costs.  SFAS No. 121 also provides
for the restoration of previously disallowed costs that are subsequently allowed
by a regulator.  The adoption of SFAS No. 121 is not expected to have an effect
on the Company's financial position or results of operations.

Discussed below are the Company's  significant  regulatory assets and regulatory
liabilities.

Base Financial Component and Rate Moderation Component

Pursuant to the 1989 Settlement,  as more fully discussed in Note 2, the Company
recorded a regulatory asset known as the Financial Resource Asset (FRA). The FRA
is  designed to provide the  Company  with  sufficient  cash flows to assure its
financial  recovery.  The FRA has two components,  the Base Financial  Component
(BFC) and the Rate Moderation Component (RMC).

The BFC  represents  the present  value of the future  net-after-tax  cash flows
which the Rate Moderation  Agreement (RMA), one of the constituent  documents of
the 1989 Settlement,  provided the Company for its financial  recovery.  The BFC
was granted  rate base  treatment  under the terms of the RMA and is included in
the Company's  revenue  requirements  through an amortization  included in rates
over forty years on a straight-line basis which began July 1, 1989.

The RMC reflects the difference between the Company's revenue requirements under
conventional  ratemaking and the revenues  resulting from the  implementation of
the rate moderation plan provided for in the RMA. The RMC is currently adjusted,
on a monthly basis,  for the Company's  share of certain Nine Mile Point Nuclear
Power Station, Unit 2 (NMP2) operations and maintenance  expenses,  fuel credits
resulting  from the  Company's  electric fuel cost  adjustment  clause and gross
receipts tax  adjustments  related to the FRA. For a further  discussion  of the
1989 Settlement and FRA, see Notes 2 and 3.

Shoreham Post-Settlement Costs

The balance  consists of Shoreham  decommissioning  costs,  fuel disposal costs,
payments-in-lieu-of-taxes,  carrying  charges and other  costs.  These costs are
being  capitalized  and amortized and recovered  through rates over a forty year
period on a  straight-line  remaining life basis which began July 1, 1989. For a
further discussion of Shoreham post-settlement costs, see Note 2.

Shoreham Nuclear Fuel

The balance  principally  reflects the unamortized  portion of Shoreham  nuclear
fuel which was  reclassified  from Nuclear Fuel in Process and in Reactor at the
time of the 1989  Settlement.  This  amount  is being  amortized  and  recovered
through rates over a forty-year  period on a straight-line  remaining life basis
which began July 1, 1989.

Unamortized Cost of Issuing Securities

The balance represents the unamortized premiums or discounts and expenses

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related to the issues of long-term debt that have been retired prior to maturity
and the costs associated with the early redemption of those issues. In addition,
this balance includes the unamortized capital stock expense and redemption costs
related to certain series of preferred  stock that have been  refinanced.  These
costs are amortized and recovered  through rates over the shorter of the life of
the redeemed issue or the new issue as provided by the PSC.

Postretirement Benefits Other Than Pensions

The Company defers as a regulatory asset the difference  between  postretirement
benefit  expense  recorded in  accordance  with SFAS No. 106 and  postretirement
benefit expense reflected in current rates. Pursuant to a PSC order, the ongoing
annual SFAS No. 106 benefit  expense must be phased into and fully  reflected in
rates by November 30, 1997,  ending with the  accumulated  deferred  asset being
recovered in rates over the next fifteen-year  period.  For a further discussion
of SFAS No. 106, see Note 8.

Regulatory Tax Asset and Regulatory Tax Liability

The Company has recorded a regulatory tax asset for amounts that it will collect
in future rates for the portion of its deferred tax  liability  that has not yet
been recognized for ratemaking  purposes.  The regulatory tax asset is comprised
principally of the tax effect of the difference in the cost basis of the BFC for
financial and tax reporting  purposes,  depreciation  differences not normalized
and the allowance for equity funds used during construction.

The  regulatory  tax  liability  is  primarily  attributable  to deferred  taxes
previously  recognized at rates higher than current enacted tax law, unamortized
investment tax credits and tax credit carryforwards.

Regulatory Liability Component

Pursuant  to the 1989  Settlement,  certain  tax  benefits  attributable  to the
Shoreham  abandonment  are to be shared  between  customers and  shareowners.  A
regulatory  liability of approximately $794 million was recorded in June 1989 to
preserve an amount  equivalent to the customer tax benefits  attributable to the
Shoreham abandonment. This amount is being amortized over a ten-year period on a
straight-line basis which began July 1, 1989.

1989 Settlement Credits

The balance  represents  the  unamortized  portion of an  adjustment of the book
write-off to the negotiated 1989 Settlement  amount. A portion of this amount is
being  amortized  over a  ten-year  period  which  began  on July 1,  1989.  The
remaining portion is not currently being recognized for ratemaking purposes.

UTILITY PLANT

Additions to and replacements of utility plant are capitalized at original cost,
which includes  material,  labor,  indirect costs associated with an addition or
replacement and an allowance for the cost of funds used during construction. The
cost of renewals and betterments relating to units of

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property is added to utility plant.  The cost of property  replaced,  retired or
otherwise  disposed of is deducted from utility plant and,  generally,  together
with dismantling costs less any salvage, is charged to accumulated depreciation.
The cost of repairs and minor renewals is charged to maintenance  expense.  Mass
properties (such as poles, wire and meters) are accounted for on an average unit
cost basis by year of installation.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION

The Uniform  Systems of Accounts  defines  the  Allowance  For Funds Used During
Construction  (AFC)  as the net cost of  borrowed  funds  used for  construction
purposes and a reasonable rate of return upon the utility's equity when so used.
AFC is not an item of current cash income.  AFC is computed monthly using a rate
permitted by FERC on a portion of  construction  work in  progress.  The average
annual AFC rate,  without  giving effect to  compounding,  was 9.36%,  9.18% and
9.73% for the years 1995, 1994 and 1993, respectively.

DEPRECIATION

The provisions for  depreciation  result from the  application of  straight-line
rates to the original cost, by groups, of depreciable properties in service. The
rates are  determined  by age-life  studies  performed  annually on  depreciable
properties. Depreciation for electric properties was equivalent to approximately
3.0% of respective  average  depreciable plant costs for each of the years 1995,
1994 and 1993.  Depreciation  for gas properties was equivalent to approximately
2.0% of respective  average  depreciable plant costs for each of the years 1995,
1994 and 1993.

CASH AND CASH EQUIVALENTS

Cash  equivalents are highly liquid  investments with maturities of three months
or less when purchased.  The carrying amount  approximates fair value because of
the short maturity of these investments.

FAIR VALUES OF FINANCIAL INSTRUMENTS

The fair values for the Company's long-term debt and redeemable  preferred stock
are based on quoted  market  prices,  where  available.  The fair values for all
other  long-term  debt  and  redeemable  preferred  stock  are  estimated  using
discounted  cash  flow  analyses  which is  based  upon  the  Company's  current
incremental borrowing rate for similar types of securities.

REVENUES

Revenues are based on cycle billings  rendered to certain  customers monthly and
others  bi-monthly.  The Company  also  accrues  electric  and gas  revenues for
services rendered to customers but not billed at month-end.

The  Company's  electric  rate  structure as discussed in Note 3, provides for a
revenue  reconciliation  mechanism  which  eliminates  the impact on earnings of
experiencing  electric  sales  that are above or below the levels  reflected  in
rates.

The Company's gas structure provides for a weather normalization clause which

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reduces the impact on revenues of experiencing weather which is warmer or colder
than normal.

FUEL COST ADJUSTMENTS

The  Company's  electric  and gas tariffs  include  fuel cost  adjustment  (FCA)
clauses which provide for the disposition of the difference  between actual fuel
costs and the fuel costs allowed in the  Company's  base tariff rates (base fuel
costs).  The Company  defers these  differences  to future periods in which they
will be billed or credited to customers,  except for base electric fuel costs in
excess of actual electric fuel costs, which are currently credited to the RMC as
incurred.

FEDERAL INCOME TAX

The Company  provides  deferred federal income tax with respect to certain items
of income and expense that are reported in  different  years for federal  income
tax purposes  and  financial  statement  purposes and with respect to items with
different bases for financial and tax reporting  purposes,  as discussed in Note
9.

The Company defers the benefit of 60% of pre-1982 gas and pre-1983  electric and
100% of all other investment tax credits,  with respect to regulated properties,
when realized on its tax returns.  Accumulated  deferred  investment tax credits
are amortized ratably over the lives of the related properties.

For ratemaking  purposes,  the Company provides deferred federal income tax with
respect to certain  differences  between  income  before  income tax and taxable
income.  Also, certain accumulated deferred federal income tax are deducted from
rate base and  amortized or otherwise  applied as a reduction in federal  income
tax expense in future years.

RESERVES FOR CLAIMS AND DAMAGES

Losses arising from claims against the Company,  including workers' compensation
claims, property damage, extraordinary storm costs and general liability claims,
are partially self-insured.  Reserves for these claims and damages are based on,
among other things, experience, risk of loss and the ratemaking practices of the
PSC. Extraordinary storm losses incurred by the Company are partially insured by
various commercial insurance carriers.  These insurance carriers provide partial
insurance coverage for individual storm losses to the Company's transmission and
distribution system between $15 million and $35 million.  Storm losses which are
outside of this range,  as well as the uninsured  layers within this range,  are
self-insured by the Company.

USE OF ESTIMATES

The  preparation  of the  financial  statements  in  conformity  with  generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that affect the amounts  reported in the financial  statements  and
accompanying notes. Actual results could differ from those estimates.


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RECLASSIFICATIONS

Certain prior year amounts have been reclassified in the financial statements to
conform with the current year presentation.


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NOTE 2. THE 1989 SETTLEMENT

On February  28,  1989,  the Company and the State of New York  entered into the
1989 Settlement  resolving certain issues relating to the Company and providing,
among  other  matters,  for the  financial  recovery  of the Company and for the
transfer of Shoreham to the Long Island Power Authority (LIPA), an agency of the
State of New York, for its subsequent decommissioning.

Upon the  effectiveness  of the  1989  Settlement,  in June  1989,  the  Company
recorded the FRA on its Balance Sheet and the  retirement  of its  investment of
approximately $4.2 billion, principally in Shoreham. The FRA has two components,
the BFC and the RMC. For a further discussion of the FRA, see Note 1.

On February 29,  1992,  the Company  transferred  ownership of Shoreham to LIPA.
Pursuant to the 1989 Settlement,  the Company was required to reimburse LIPA for
all of its costs associated with the decommissioning of Shoreham.  Effective May
1, 1995, the Nuclear  Regulatory  Commission (NRC) terminated  LIPA's possession
-only license for Shoreham.  The  termination  signified the NRC's approval that
decommissioning was complete and that the site is suitable for unrestricted use.
At December 31,  1995,  Shoreham  post-settlement  costs  totaled  approximately
$1.052   billion,   consisting   of  $487   million   of   property   taxes  and
payments-in-lieu-of-taxes,  and $565  million  of  decommissioning  costs,  fuel
disposal costs and all other costs incurred at Shoreham after June 30, 1989.

The PSC has  determined  that all  costs  associated  with  Shoreham  which  are
prudently  incurred by the Company  subsequent to the  effectiveness of the 1989
Settlement are decommissioning  costs. The RMA provides for the recovery of such
costs  through  electric  rates over the balance of a forty-year  period  ending
2029.


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NOTE 3. RATE MATTERS

ELECTRIC

In 1993,  the Company  filed an  Electric  Rate Plan (Plan) with the PSC for the
three-year  period which began December 1, 1994. The goals of this Plan included
minimizing  future  electric  rate  increases in addition to  providing  for the
continued   recovery  of  the  Company's   regulatory   assets  while  retaining
consistency  with the Rate Moderation  Agreement's  (RMA) objective of restoring
the Company to financial health. As a result of the rate proceeding initiated by
the filing of the Company's Plan, the PSC issued an Order, in 1995, for the rate
year  beginning  December  1, 1994,  which  among other  things,  froze  overall
electric rates, reduced the Company's allowed return on common equity from 11.6%
to 11.0%,  and modified or eliminated  certain  performance-based  incentives as
discussed  below under the heading  "Modifications  to the LILCO  Ratemaking and
Performance Plan".

In addition,  the PSC ordered that the rate proceeding be continued to allow the
parties to develop a plan for achieving  long-term rate stability,  while, among
other things,  providing  for the  continuing  recovery of the  Shoreham-related
assets.  In its rate  decision,  the PSC  reaffirmed its commitment to allow the
Company to recover  its  Shoreham-related  assets,  noting  that it is a crucial
factor in the Company's ability to maintain its investment grade bond rating and
to secure  reasonably  priced capital.  The  continuation of the rate proceeding
will  also  enable  the  PSC  to  consider  the  Company's  operations  and  its
opportunities for greater efficiency over the next several years.

In 1995, the Company,  through a compliance filing,  requested a continuation of
the rate freeze for the rate year beginning December 1, 1995. The PSC has yet to
issue an electric rate order in response to this filing.

In  February  1996,  the PSC  issued  an order to show  cause and  instituted  a
proceeding to examine  various  opportunities  to reduce the  Company's  current
electric  rates.  Specifically,  the  Company  has been  directed to address the
following:  (i) should all or a part of the $81 million  Suffolk County property
tax refund that the Company received in January 1996,  pursuant to a judgment in
the Company's  favor that found that the Shoreham  property was  overvalued  for
property tax purposes between 1976 and 1983 (excluding 1979 which had previously
been settled),  be used to reduce  current rates;  (ii) should the return of the
$26 million 1995 rate year net reconciliation credit to customers, as more fully
discussed below, be accelerated;  (iii) determine,  upon review of the forecasts
reflected in the September 1995  compliance  filing for the rate year commencing
December 1, 1995, whether  adjustments to the forecasts can be reflected in rate
reductions  currently;  and (iv) revisit the current  mechanics of the Fuel Cost
Adjustment (FCA) clause, as more fully discussed in Note 1, to determine whether
all or a portion of any fuel cost savings can be  reflected in current  customer
bills.

The  Company  has been  directed to submit a response to the order to show cause
addressing  these items.  Interested  parties will have an opportunity to submit
comments on the Company's  filing,  after which a hearing  before an ALJ will be
convened and the ALJ will determine further procedures. The Company

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is unable to predict the outcome of this proceeding and the impact, if any, that
it may have on the Company's  cash flow,  financial  condition or results of its
operations.

While no assurances  can be given,  the  Company's  objective is to continue the
current rate freeze through the rate year ending November 30, 1997.

Rate Moderation Component

The RMA, one of the constituent  documents of the 1989 Settlement,  provides for
the full recovery of the RMC. The RMC balance represents deferred revenues to be
collected from customers which result from the difference  between  conventional
revenue  requirements  and revenues  provided for under the 1989  Settlement and
subsequent rate orders. Prior to December 31, 1992, the RMC had increased as the
difference  between  revenues  resulting  from  the  implementation  of the rate
moderation  plan  provided  for  in  the  RMA  and  revenue  requirements  under
conventional  ratemaking,  together  with  a  carrying  charge  computed  at the
Company's  allowed return on common equity,  was deferred.  The RMC had provided
the Company with a  substantial  amount of non-cash  earnings from the effective
date of the 1989 Settlement  through  December 31, 1992. For the period December
31, 1992 through  December 31, 1994,  the RMC balance had  decreased as revenues
resulting  from the  operation  of the rate  moderation  plan  exceeded  revenue
requirements under conventional ratemaking.

During 1995, the Company was able to reduce the RMC balance by approximately $80
million by applying  credits  generated by the operation of the  Company's  Fuel
Moderation  Component  Mechanism  (FMC),  as described  below,  and by crediting
certain deferred customer benefits to the RMC, as prescribed by the PSC. The FMC
and deferred customer  benefits,  which amounted to $87 million and $86 million,
respectively,  more than offset the accretion of the RMC resulting from revenues
under the  current  electric  rate order being less than the  Company's  revenue
requirements under conventional ratemaking.

The FMC  mechanism,  which is included in the Company's  FCA clause,  allows the
Company to  collect  the higher of the base cost of fuel  included  in  electric
rates or the actual cost of fuel.  The actual cost of fuel consumed for electric
generation for 1995 was  approximately  $87 million below the base cost of fuel,
enabling  the  Company  to use this  excess to credit  and thus  reduce  the RMC
balance.  For the years ended December 31, 1994 and 1993,  the Company  credited
the RMC balance $83 million and $45  million,  respectively,  as a result of the
operation of the FMC mechanism.

To assist in the recovery of the RMC balance,  the Company, as authorized by the
PSC,  has credited the RMC with $86 million of deferred  customer  benefits,  as
noted above.  These  credits  consisted  principally  of: (i)  deferred  amounts
collected in rates that because of the Company's cost  containment  programs had
not been  expended  for  enhanced  reliability  and  production  operations  and
maintenance  expenses during the term of the LRPP; (ii) net litigation  proceeds
related to the  construction  of Shoreham;  and (iii)  proceeds from the sale of
sulfur  dioxide  emissions  credits.  For the years ended  December 31, 1994 and
1993,  the Company  credited the RMC balance  with  deferred  customer  benefits
totaling $5.1 million and $10.1 million, respectively.



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Modifications to the Lilco Ratemaking and Performance Plan

In November 1991, the PSC approved the Lilco  Ratemaking  and  Performance  Plan
(LRPP). The LRPP contained three major components:  (i) revenue  reconciliation;
(ii)  expense  attrition  and   reconciliation;   and  (iii)   performance-based
incentives.  In its latest electric rate order,  the PSC has continued the three
major  components of the LRPP with  modifications  to the expense  attrition and
reconciliation  mechanism  and the  performance-based  incentives.  The  revenue
reconciliation mechanism remains unchanged.

Revenue  reconciliation  provides  a  mechanism  that  eliminates  the impact of
experiencing  sales that are above or below  adjudicated  levels by  providing a
fixed annual net margin level (defined as sales  revenues,  net of fuel expenses
and gross receipts  taxes).  The difference  between actual and  adjudicated net
margin levels are deferred on a monthly basis during the rate year.

The expense attrition and  reconciliation  component permits the Company to make
adjustments  for certain  expenses  recognizing  that these cost  increases  are
unavoidable  due to  inflation  and changes  outside the control of the Company.
Pursuant to the current electric rate order,  which became effective December 1,
1994,  the Company is permitted to reconcile  expenses for property  taxes only,
whereas under the original  LRPP the Company was able to reconcile  expenses for
wage rates,  property  taxes,  interest costs and demand side  management  (DSM)
costs.

The original LRPP had also provided for the deferral and amortization of certain
cost variances for enhanced  reliability,  production operations and maintenance
expenses and the application of an inflation index to other expenses.  Under the
current rate order,  these  deferrals have been  eliminated and any  unamortized
balances were credited to the RMC during 1995.

The modified  performance-based  incentive programs include the DSM program, the
customer  service  performance  program and the  transmission  and  distribution
reliability program.  Under these revised programs,  the Company is subject to a
maximum  penalty of 38 basis points of the allowed  return on common  equity and
can earn up to 4 basis points under the customer service  program.  This 4 basis
point incentive can only be used to offset a penalty under the  transmission and
distribution  reliability  program.  Under the  original  LRPP,  the Company was
allowed to earn up to 40 basis  points or forfeit  up to 18 basis  points  under
these incentive programs.

The partial  passthrough fuel incentive  program remains  unchanged.  Under this
incentive,  the Company can earn or forfeit up to 20 basis points of the allowed
return on common equity.

For the rate year ended  November 30, 1995,  the Company earned 19 basis points,
or  approximately  $4.0  million,  net  of  tax  effects,  as a  result  of  its
performance  under  all  incentive  programs.  In each of the rate  years  ended
November  30,  1994  and  1993,  the  Company  earned  50 and 49  basis  points,
respectively,  or  approximately  $9.2  million,  net of tax effects,  under the
incentive programs in effect at those times.

The deferred balances resulting from the net margin expense reconciliations,

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and earned performance-based  incentives are netted at the end of each rate year
and, as established  under the LRPP and continuing under the current rate order,
the first $15 million of the total  deferral is used to increase or decrease the
RMC balance.  Deferrals in excess of the $15 million,  upon approval of the PSC,
are refunded to or recovered from the customers through the FCA mechanism over a
12-month period.

For the rate  year  ended  November  30,  1995,  the  amount to be  returned  to
customers   resulting   from   the   revenue   and   expense    reconciliations,
performance-based incentive programs and associated carrying charges totaled $41
million.  In accordance with the current electric rate order, and as established
under the LRPP, the first $15 million of the deferral will be used to reduce the
RMC.  The  remaining  balance of $26  million is  expected to be returned to the
customers  through  the FCA over a 12-month  period.  For the rate  years  ended
November  30,  1994  and  1993,  the  Company   recorded   deferred  charges  of
approximately $79 million and $63 million,  respectively.  The first $15 million
of the rate year ended  November  30, 1993 was applied as an increase to the RMC
while the  remaining  deferrals of $48 million  were  recovered  from  customers
through the FCA. It is  anticipated  that the first $15 million of deferrals for
the rate year ended November 30, 1994 will be  reclassified  to increase the RMC
balance upon approval by the PSC of the Company's pending  reconciliation filing
and that the remaining $64 million will be recovered from customers  through the
FCA.

Another  provision  of the LRPP,  which is  continuing  under the  current  rate
structure,  is a mechanism  whereby  earnings in excess of the allowed return on
common  equity,  excluding the impacts of the various  incentive  and/or penalty
programs, are used to reduce the RMC. For the rate year ended November 30, 1995,
the Company  earned $3.3 million,  net of tax effects,  in excess of its allowed
return on common  equity  which was fully  applied as a reduction to the RMC. In
1994, the Company did not earn in excess of its allowed return on common equity,
while for the rate year  ended  November  30,  1993,  the  Company  earned  $8.9
million,  net of tax effects,  in excess of the allowed  return on common equity
which was shared  equally  between  customers  (by a  reduction  to the RMC) and
shareowners.  Under the  modified  mechanism  currently  in  effect,  all excess
earnings are allocated to customers via a reduction to the RMC.

GAS

In December 1993, the PSC approved a three-year gas rate settlement  between the
Company  and the Staff of the PSC.  The gas rate  settlement  provides  that the
Company receive, for each of the rate years beginning December 1, 1993, 1994 and
1995,  annual gas rate increases of 4.7%,  3.8% and 3.2%,  respectively.  In the
determination  of the  revenue  requirements  for the gas  rate  settlement,  an
allowed  return on common  equity of 10.1% was used.  The gas rate decision also
provides  that  earnings in excess of a 10.6% return on common  equity be shared
equally  between the Company's firm gas customers and its  shareowners.  For the
rate years ended November 30, 1995,  and 1994, the Company earned  approximately
$1.5 million and $9.2 million,  net of tax effects,  respectively,  in excess of
the 10.6%  return on common  equity.  The firm gas  customers'  portion of these
excess earnings amounting to $0.8 million and $4.6 million,  net of tax effects,
respectively,  has been deferred.  The PSC has granted the Company permission to
retain the customers'  portion of the 1994 rate year excess earnings through the
term of

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the gas rate settlement agreement and apply such excess earnings to the recovery
of deferred  Postretirement  Benefits  Other Than Pensions or  manufactured  gas
plant (MGP) site  cleanup  costs.  For a further  discussion  of  Postretirement
Benefits  Other Than Pensions and MGP costs,  see Notes 8 and 10,  respectively.
The Company has requested that the same treatment be granted for the disposition
of the customer's  portion of the 1995 rate year excess  earnings which amounted
to $1.5 million.



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NOTE 4. THE CLASS SETTLEMENT

The Class Settlement,  which became effective on June 28, 1989, resolved a civil
lawsuit against the Company brought under the federal  Racketeer  Influenced and
Corrupt Organizations Act. The lawsuit, which the Class Settlement resolved, had
alleged that the Company made inadequate  disclosures  before the PSC concerning
the construction and completion of nuclear generating facilities.

The  Class  Settlement  provides  the  Company's  electric  customers  with rate
reductions  aggregating  $390  million.  Upon  its  effectiveness,  the  Company
recorded its liability for the Class Settlement on a present value basis at $170
million  and  simultaneously  recorded a charge to income (net of tax effects of
$57 million) of approximately  $113 million.  The Class Settlement  provides the
Company's  electric  customers  with  reductions  that are  being  reflected  as
adjustments to their monthly  electric bills over a ten-year  period which began
on June 1, 1990.  The  remaining  reductions  to customers  bills,  amounting to
approximately  $247 million as of December 31, 1995,  consists of  approximately
$17 million for the five-month period beginning January 1, 1996, $50 million for
the  12-month  period  beginning  June 1, 1996 and $60  million  for each of the
12-month periods beginning June 1, 1997, 1998 and 1999, respectively.



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NOTE 5. NINE MILE POINT NUCLEAR POWER STATION, UNIT 2

The Company has an 18% undivided interest in NMP2, located near Oswego, New York
which is operated by Niagara Mohawk Power Corporation (NMPC).  Ownership of NMP2
is shared by five  cotenants:  the Company  (18%),  NMPC  (41%),  New York State
Electric & Gas Corporation (18%),  Rochester Gas and Electric  Corporation (14%)
and Central  Hudson Gas & Electric  Corporation  (9%). At December 31, 1995, the
Company's  utility  plant  investment  in NMP2  included  in rate  base was $740
million, net of accumulated  depreciation of $153 million.  Generation from NMP2
and operating  expenses  incurred by NMP2 are shared in the same  proportions as
the cotenants' respective ownership interests.  The Company's share of operating
expenses  is  included on its  Statement  of Income.  The Company is required to
provide its  respective  share of financing  for any capital  additions to NMP2.
Nuclear fuel costs  associated with NMP2 are being amortized on the basis of the
quantity of heat produced for the generation of electricity.

NMPC has contracted with the United States Department of Energy for the disposal
of spent nuclear fuel. The Company reimburses NMPC for its 18% share of the cost
under the contract at a rate of $1.00 per megawatt hour of net generation less a
factor to account for  transmission  line losses.  For 1995, 1994 and 1993, this
totaled $1.2 million, $1.4 million, and $1.0 million, respectively.

NMPC expects to commence the  decommissioning of NMP2 in 2026, shortly after the
cessation of plant operations,  using a method which provides for the removal of
all equipment and  structures  and the release of the property for  unrestricted
use. In 1995, NMPC completed a decommissioning study for NMP2 (1995 study) which
is  currently  under  evaluation  by the  Company and the other  cotenants.  The
Company's share of decommissioning costs under the 1995 study is estimated to be
$418 million in 2026 dollars ($145  million in 1995  dollars).  Previously,  the
Company's share of decommissioning costs was $234 million in 2026 dollars, which
was based  upon a 1989  study  which was  updated to reflect a change in the NRC
minimum decommissioning  funding requirement.  The increase included in the 1995
study is primarily  due to the  inclusion  of nuclear  fuel storage  charges and
costs for  continuing  care of the  nuclear  site.  The  Company's  share of the
estimated  decommissioning  costs, based upon the 1989 study, is currently being
provided  for  in  electric   rates  and  is  being  charged  to  operations  as
depreciation  expense  over  the  expected  service  life of NMP2.  The  Company
believes that the incremental decommissioning costs identified in the 1995 study
will also be recoverable  through  rates.  The amount of  decommissioning  costs
recorded as depreciation  expense in 1995, 1994 and 1993 was $2.3 million,  $1.6
million and $1.7 million,  respectively.  The accumulated  decommissioning costs
collected in rates  through  December 31, 1995,  1994 and 1993 amounted to $11.0
million, $8.7 million and $7.1 million, respectively.

The  Company  has  established  trust  funds  for  the  decommissioning  of  the
contaminated  portion of the NMP2 plant. It is currently estimated that the cost
to decommission the contaminated  portion of the plant will be approximately 77%
of the total  decommissioning  costs. These funds comply with regulations issued
by the NRC and FERC  governing  the  funding  of nuclear  plant  decommissioning
costs. The Company's policy is to make contributions to the funds based upon the
amount of decommissioning costs collected in

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rates. As of December 31, 1995, the balance in these funds, including reinvested
net earnings, was approximately $10.3 million. These amounts are included on the
Company's Balance Sheet in Special deposits. The trust funds investment consists
of U.S. Treasury debt securities and cash  equivalents.  The carrying amounts of
these instruments approximate fair market value.

The  Financial  Accounting  Standards  Board  issued an  exposure  draft in 1996
entitled  "Accounting for Certain  Liabilities  Related to Closure or Removal of
Long-Lived  Assets".  If the provisions of the exposure draft were adopted,  the
Company  would be  required  to change  its  current  accounting  practices  for
decommissioning costs as follows: (i) the Company's share of the total estimated
decommissioning costs would be accounted for as a liability, based on discounted
future cash flows;  (ii) the  recognition  of the liability for  decommissioning
costs would result in a corresponding  increase to the cost of the nuclear plant
rather than as depreciation expense; and (iii) investment earnings on the assets
dedicated  to the  external  decommissioning  trust  fund would be  recorded  as
investment  income rather than as an increase to accumulated  depreciation.  The
Company cannot  presently  predict the impact,  if any, that this exposure draft
will have on the Company's financial condition.



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NOTE 6. CAPITAL STOCK

COMMON STOCK

The  Company  has  150,000,000  shares  of  authorized  common  stock,  of which
119,655,441  were issued and  outstanding  at December 31, 1995. The Company has
1,707,443  shares  reserved for sale through its Employee  Stock  Purchase Plan,
3,812,382  shares  committed to the  Automatic  Dividend  Reinvestment  Plan and
112,798  shares  reserved for  conversion of the Series I Convertible  Preferred
Stock at a rate of $17.15 per share.

PREFERRED STOCK

The Company has 7,000,000  authorized  shares,  cumulative  preferred stock, par
value $100 per share and  30,000,000  authorized  shares,  cumulative  preferred
stock,  par  value  $25 per  share.  Dividends  on  preferred  stock are paid in
preference  to dividends on common  stock or any other stock  ranking  junior to
preferred stock.

Preferred Stock Subject to Mandatory Redemption

The  aggregate  fair  value  of  redeemable   preferred   stock  with  mandatory
redemptions at December 31, 1995 and 1994 amounted to approximately $598 million
and $564  million,  respectively,  compared  to their  carrying  amounts of $644
million and $649  million,  respectively.  For a further  discussion on the fair
value of the securities discussed above, See Note 1.

Each year the Company is required to redeem  certain  series of preferred  stock
through the operation of sinking fund provisions as follows:


                    Redemption         Number      Redemption
 Series        Provision Beginning    of Shares      Price
      L        July 31, 1979            10,500        $100
      R        December 15, 1982        37,500         100
      NN       March 1, 1999            77,700          25
      UU       October 15, 1999        112,000          25

In addition,  the Company has the non-cumulative  option to double the number of
shares to be redeemed  pursuant to the sinking fund  provisions  in any year for
the preferred stock series NN and UU. The aggregate par value of preferred stock
required to be redeemed  through  sinking  funds in 1996 is $4.8  million,  $1.1
million in 1997 and 1998 and $5.8 million in 1999 and 2000.


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The Company is also required to redeem all shares of certain series of preferred
stock  which  are not  subject  to  sinking  fund  requirements.  The  mandatory
redemption requirements for these series are as follows:



                            Redemption             Number of         Redemption
     Series                    Date                 Shares           Amounts

$1.67 Series GG            March 1, 1999             880,000        $ 22,000,000
7.95% Series AA            June 1, 2000           14,520,000         363,000,000
7.05% Series QQ            May 1, 2001             3,464,000          86,600,000
7.66% Series CC            August 1, 2002            570,000          57,000,000

Preferred Stock Not Subject to Mandatory Redemption

The Company has the option to redeem certain series of its preferred  stock. For
the series subject to optional  redemption at December 31, 1995, the call prices
were as follows:


    Series                          Call Price
5.00%  Series B                           $101
4.25%  Series D                            102
4.35%  Series E                            102
4.35%  Series F                            102
5 1/8% Series H                            102
5 3/4% Series I - Convertible              100

PREFERENCE STOCK

At  December   31,   1995,   none  of  the   authorized   7,500,000   shares  of
nonparticipating preference stock, par value $1 per share, which ranks junior to
preferred stock, were outstanding.




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NOTE 7. LONG-TERM DEBT

G&R MORTGAGE

During 1995,  the Company  retired the remaining  $100 million of First Mortgage
Bonds with cash on hand.  As a result,  the lien of the First  Mortgage has been
discharged making the General and Refunding Bonds (G&R Bonds) the Company's only
outstanding  secured  indebtedness.  The G&R Mortgage is a lien on substantially
all of the Company's properties.

The annual G&R Mortgage  sinking fund  requirement  for 1995, due not later than
June 30, 1996, is estimated at $25 million.  The Company expects to satisfy this
requirement with retired G&R Bonds, plant additions or with cash on hand, or any
combination thereof.

1989 REVOLVING CREDIT AGREEMENT

The Company has available  through  October 1, 1996, $300 million under its 1989
Revolving Credit Agreement (1989 RCA). This line of credit is secured by a first
lien  upon the  Company's  accounts  receivable  and fuel  oil  inventories.  At
December 31, 1995, no amounts were  outstanding  under the 1989 RCA. The Company
has agreed to pay a fee of one  quarter of one  percent  per annum on the unused
portion.  The 1989 RCA may be extended for one-year  periods upon the acceptance
by the lending banks of a request by the Company, which must be delivered to the
lending  banks  prior to April 1 of each  year.  It is the  Company's  intent to
request an extension prior to April 1, 1996.

AUTHORITY FINANCING NOTES

Authority Financing Notes are issued by the Company to the New York State Energy
Research  and  Development  Authority  (NYSERDA)  to secure  certain  tax-exempt
Industrial  Development  Revenue Bonds,  Pollution Control Revenue Bonds (PCRBs)
and Electric  Facilities  Revenue  Bonds (EFRBs)  issued by NYSERDA.  Certain of
these bonds are subject to periodic  tender,  at which time their interest rates
may be subject to redetermination.



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Tender  requirements  of Authority  Financing Notes at December 31, 1995 were as
follows:

                                                       (In thousands of dollars)
            Interest
              Rate     Series       Principal        Tendered

PCRBs        8 1/4%    1982        $ 17,200     Tendered every three
                                                years, next tender
                                                October 1997

              4.70%    1985 A,B     150,000     Tendered annually on
                                                March 1

EFRBs         5.00%    1993 A        50,000     Tendered weekly
              5.05%    1993 B        50,000     Tendered weekly
              4.95%    1994 A        50,000     Tendered weekly
              5.00%    1995 A        50,000     Tendered weekly


The 1995,  1994 and 1993  EFRBs and the 1985 PCRBs are  supported  by letters of
credit  pursuant  to which the  letter of credit  banks  have  agreed to pay the
principal,  interest  and  premium,  if  applicable,  in  the  aggregate,  up to
approximately  $381  million  in the event of  default.  The  obligation  of the
Company to reimburse the letter of credit banks is unsecured.

The expiration dates for these letters of credit are as follows:


                   Series          Expiration Date

PCRBs              1985 A,B        March 16, 1999

EFRBs              1993 A,B        November 17, 1996
                   1994 A          October 26, 1997
                   1995 A          August 24, 1998

Prior to  expiration,  the Company is required to obtain  either an extension of
the  letters  of credit or a  substitute  credit  facility.  If  neither  can be
obtained,  the authority  financing notes supported by letters of credit must be
redeemed.  In 1996,  the  Company  amended the letter of credit for the PCRBs to
extend the stated expiration date to March 16, 1999.


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<PAGE>



FAIR VALUES OF LONG-TERM DEBT

The carrying amounts and fair values of the Company's long-term debt at December
31 were as follows:


                                             (In thousands of dollars)
1995
                                              FAIR          CARRYING
                                              VALUE           AMOUNT
General and Refunding Bonds                $1,968,173      $1,951,000
Debentures                                  2,245,138       2,270,000
Authority Financing Notes                     928,967         916,675
Total                                      $5,142,278      $5,137,675


1994
First Mortgage Bonds                       $   95,688      $  100,000
General and Refunding Bonds                 1,844,289       1,951,000
Debentures                                  1,867,510       2,270,000
Authority Financing Notes                     829,651         866,675
Total                                      $4,637,138      $5,187,675

For a further  discussion on the fair value of the securities  listed above, see
Note 1.


MATURITY SCHEDULE

The total  long-term debt maturing in each of the next five years is as follows:
1996, $415 million;  1997, $251 million; 1998, $101 million; 1999, $454 million;
and 2000, $37 million.



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NOTE 8. RETIREMENT BENEFIT PLANS

PENSION PLANS

The Company maintains a defined benefit pension plan which covers  substantially
all employees  (Primary  Plan),  a supplemental  plan which covers  officers and
certain key executives  (Supplemental  Plan) and a retirement  plan which covers
the Board of Directors  (Directors'  Plan).  The Company also  maintains  401(k)
plans for its union and non-union employees to which it does not contribute.

Primary Plan

The Company's  funding  policy is to  contribute  annually to the Primary Plan a
minimum  amount  consistent  with the  requirements  of the Employee  Retirement
Income Security Act of 1974 (ERISA) plus such additional amounts, if any, as the
Company may determine to be appropriate from time to time.  Pension benefits are
based upon years of service and compensation.

The Primary Plan's funded status and amounts  recognized on the Balance Sheet at
December 31, 1995 and 1994 were as follows:

                                                (In thousands of dollars)
                                                      1995        1994
Actuarial present value of benefit obligation
  Vested benefits                               $  518,487    $  467,962
  Nonvested benefits                                54,305        50,385
Accumulated Benefit Obligation                  $  572,792    $  518,347

Plan assets at fair value                       $  685,300    $  597,200
Actuarial present value of projected
  benefit obligation                               662,360       592,339
Projected benefit obligation less
  than plan assets                                  22,940         4,861
Unrecognized net obligation                         77,831        84,577
Unrecognized net gain                              (97,285)      (90,335)
Net Prepaid (Accrued) Pension Cost             $     3,486    $     (897)




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<PAGE>



Periodic pension cost for the Primary Plan included the following components:

                                                 (In thousands of dollars)
                                             1995          1994           1993

Service cost - benefits
  earned during the period              $  15,385     $  16,465      $  14,481
Interest cost on projected benefit
  obligation and service cost              45,987        43,782         41,865
Actual return on plan assets             (102,099)      (12,431)       (54,010)
Net amortization and deferral              57,665       (31,633)        10,025
Net Periodic Pension Cost               $  16,938     $  16,183      $  12,361


Assumptions used in accounting for the Primary Plan were as follows:

                                            1995     1994     1993
Discount rate                               7.25%    7.75%   7.25%
Rate of future compensation increases       5.00%    5.00%   5.00%
Long-term rate of return on assets          7.50%    7.50%   7.50%

The Primary Plan assets at fair value  include  cash,  cash  equivalents,  group
annuity contracts, bonds and listed equity securities.

In 1993,  the PSC issued an Order which  addressed the accounting and ratemaking
treatment  of  pension  costs  in  accordance  with  SFAS  No.  87,  "Employers'
Accounting for Pensions".  Under the Order, the Company is required to recognize
any  deferred net gains or losses over a ten-year  period  rather than using the
corridor  approach  method.  This change in the annual pension cost  calculation
reduced  pension  expense by $4.6  million in the year of  adoption,  1993.  The
Company believes that this method of accounting for financial reporting purposes
results in a better  matching of revenues and the Company's  pension  cost.  The
Company defers  differences  between  pension rate allowance and pension expense
under the Order.  In  addition,  the PSC  requires  the  Company to measure  the
difference   between  the  pension  rate   allowance  and  the  annual   pension
contributions contributed into the pension fund.

Supplemental Plan

The Supplemental Plan, the cost of which is borne by the Company's  shareowners,
provides  supplemental death and retirement  benefits for officers and other key
executives without contribution from such employees.  The Supplemental Plan is a
non-qualified plan under the Internal Revenue Code. Death benefits are currently
provided by  insurance.  The provision  for plan  benefits,  which are unfunded,
totaled  approximately  $2.3 million in both 1995 and 1994,  and $2.8 million in
1993.

Directors' Plan

The Directors'  Plan provides  benefits to directors who are not officers of the
Company.  Directors  who have served in that  capacity  for more than five years
qualify as  participants  under the plan. The Directors' Plan is a non-qualified
plan under the Internal  Revenue Code.  The provision for  retirement  benefits,
which are unfunded, totaled approximately $114,000,

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<PAGE>



$148,000, and $150,000 in 1995, 1994 and 1993, respectively.

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

In addition to providing pension benefits,  the Company provides certain medical
and life  insurance  benefits for retired  employees.  Substantially  all of the
Company's  employees  may  become  eligible  for these  benefits  if they  reach
retirement age after working for the Company for a minimum of five years.  These
and similar  benefits  for active  employees  are  provided by the Company or by
insurance  companies  whose  premiums are based on the benefits  paid during the
year.  Effective January 1, 1993, the Company adopted the provisions of SFAS No.
106,  "Employers'  Accounting for Postretirement  Benefits Other Than Pensions",
which  requires  the  Company  to  recognize  the  expected  cost  of  providing
postretirement  benefits  when employee  services are rendered  rather than when
paid. As a result, the Company, in 1993, recorded an accumulated  postretirement
benefit  obligation and a corresponding  regulatory asset of approximately  $376
million.  Additionally,  as a result of  adopting  SFAS No. 106,  the  Company's
postretirement  benefit cost for 1993  increased by $28 million above the amount
that would have been recorded under the pay-as-you-go method.

In 1993, the PSC issued an Order which required that the effects of implementing
SFAS No. 106 be phased into rates.  The Order requires the Company to defer as a
regulatory asset the difference between  postretirement benefit expense recorded
for accounting  purposes in accordance with SFAS No. 106 and the  postretirement
benefit expense  reflected in rates. The ongoing annual  postretirement  benefit
expense  will be phased  into and fully  reflected  in rates  within a five-year
period  from the year of  adoption,  which  began  December  1,  1993,  with the
accumulated  regulatory  asset being  recovered in rates over a 15-year  period,
beginning  December 1, 1997.  In addition,  the Company is required to recognize
any deferred net gains or losses over a ten-year period.

In 1994, the Company established  Voluntary Employee's  Beneficiary  Association
(VEBA) trusts for union and non-union  employees for the funding of  incremental
costs  collected  in rates for  postretirement  benefits.  For the  years  ended
December 31, 1995 and 1994, the Company funded the trusts with approximately $50
million and $2 million, respectively.



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<PAGE>



Accumulated postretirement benefit obligation other than pensions at December 31
was as follows:
                                          (In thousands of dollars)
                                                1995          1994
Retirees                                     $ 135,497      $ 159,590
Fully eligible plan participants                52,028         57,788
Other active plan participants                 142,035        133,030
Accumulated postretirement
  benefit obligation                         $ 329,560      $ 350,408
Plan assets                                    (53,646)        (2,200)
Accumulated postretirement benefit
  obligation in excess of plan
  assets                                       275,914        348,208
Unrecognized net gain                          100,335         73,936
Accrued Postretirement Benefit Cost          $ 376,249      $ 422,144


At  December  31,  1995,  the Plan  assets at fair value  include  cash and cash
equivalents  of $53.5  million  and  listed  equity  securities  of the  Company
representing  $0.1 million.  At December 31, 1994, the Plan assets at fair value
include cash and cash equivalents of approximately $2.2 million.

Periodic  postretirement  benefit cost other than pensions for the years were as
follows:

                                             1995           1994          1993
Service cost - benefits
  earned during the period              $   9,082       $ 11,275      $ 12,980
Interest cost on projected
  benefit obligation and
  service cost                             22,412         25,713        29,531
Actual return on plan assets               (1,034)              -            -
Amortization of net gain                  (14,699)        (5,213)            -
Periodic Postretirement
  Benefit Cost                          $  15,761       $ 31,775     $  42,511

Assumptions  used to determine the  postretirement  benefit  obligation  were as
follows:

                                              1995         1994    1993
Discount rate                                 7.25%       7.75%    7.25%
Rate of future compensation increases         5.00%       5.00%    5.00%
Long-term rate of return on assets            7.50%          -        -


The  assumed  health  care cost trend rates used in  measuring  the  accumulated
postretirement  benefit  obligation  at December 31, 1995 and 1994 were 8.5% and
9.0%,  respectively,  gradually declining to 6.0% in 2001 and thereafter.  A one
percentage  point increase in the health care cost trend rate would increase the
accumulated  postretirement  benefit obligation as of December 31, 1995 and 1994
by approximately $36 million and $44 million,  respectively,  and the sum of the
service  and  interest  costs  in 1995 and 1994 by $4  million  and $6  million,
respectively.

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NOTE 9. FEDERAL INCOME TAX

At December 31, the significant  components of the Company's deferred tax assets
and liabilities calculated under the provisions of SFAS No. 109 were as follows:
                                                  (In thousands of dollars)
                                                   1995           1994
Deferred Tax Assets
Net operating loss carryforwards                 $ 338,921         $   552,917
Reserves not currently deductible                   66,825              86,267
Tax depreciable basis in excess
  of book                                           41,428              48,557
Nondiscretionary excess credits                     29,826              31,933
Credit carryforwards                               149,545             142,329
Other                                              125,246              89,763
Total Deferred Tax Assets                       $  751,791         $   951,766

Deferred Tax Liabilities
1989 Settlement                                $  2,155,418        $  2,174,729
Accelerated depreciation                            628,475             608,302
Call premiums                                        50,062              56,324
Rate case deferrals                                  28,971              55,598
Other                                                35,597              46,840
Total Deferred Tax Liabilities                    2,898,523           2,941,793
Net Deferred Tax Liability                    $   2,146,732        $  1,990,027

SFAS No. 109 requires  utilities to establish  regulatory assets and liabilities
for the portion of its  deferred  tax assets and  liabilities  that have not yet
been  recognized  for  ratemaking  purposes.   The  major  components  of  these
regulatory assets and liabilities are as follows:

                                             (In thousands of dollars)
                                               1995            1994
Regulatory Assets
1989 Settlement                          $   1,666,744         $  1,672,820
Plant items                                    149,520              169,743
Other                                          (13,881)             (10,874)
Total Regulatory Assets                  $   1,802,383         $  1,831,689

Regulatory Liabilities
Carryforward credits                     $      82,330         $     75,114
Other                                           33,730               36,104
Total Regulatory Liabilities             $     116,060         $    111,218





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The federal  income tax amounts  included in the Statement of Income differ from
the amounts which result from applying the statutory  federal income tax rate to
income  before  income  tax.  The table  below sets forth the  reasons  for such
differences.

                                                 (In thousands of dollars)
                                          1995       1994          1993
Income before federal income tax      $ 508,824   $ 478,564      $ 468,839
Statutory federal income tax rate           35%          35%           35%
Statutory federal income tax         $ 178,088    $ 167,497      $ 164,094

Additions (reductions) in federal
  income tax
  Excess of book depreciation over
    tax depreciation                    18,588       14,745        12,437
  1989 Settlement                        4,213        4,213         4,256
  Interest capitalized                   2,218        2,449         3,443
  Tax credits                           (1,025)      (2,058)       (5,586)
  Rate case adjustments                  3,752       (4,779)       (1,285)
  Allowance for funds used during
  construction                          (2,392)      (2,450)       (2,304)
  Other items                            2,096       (2,905)       (2,779)
Total Federal Income Tax Expense     $ 205,538    $ 176,712     $ 172,276
Effective Federal Income Tax Rate         40.4%        36.9%         36.7%


The Company's  net operating  loss (NOL)  carryforwards  for federal  income tax
purposes are  estimated to be  approximately  $968 million at December 31, 1995.
The Company  anticipates that it will fully utilize its NOL carryforwards by the
end of 1997, however,  should they not be utilized they will expire in the years
2004  through  2007.  The  Company  currently  has tax credit  carryforwards  of
approximately  $150 million.  This balance is composed of investment  tax credit
(ITC) carryforwards,  net of the 35% reduction required by the Tax Reform Act of
1986,  totaling  approximately $142 million and research and development credits
totaling  approximately $8 million.  The credit carryforwards will expire in the
years 1998 through 2010. For financial reporting purposes, a valuation allowance
was  not  required  to  offset  the   deferred  tax  assets   related  to  these
carryforwards.  Realization is dependent on generating sufficient taxable income
prior to  expiration  of the loss  carryforwards.  Although  realization  is not
assured,  the  Company  believes  it is more  likely  than  not  that all of the
deferred  tax assets will be  realized.  The amount of the  deferred  tax assets
considered  realizable,  however, could be reduced in the near term if estimates
of future taxable income during the carryforward period are reduced.

In 1990 and 1992,  the Company  received  Revenue  Agents'  Reports  disallowing
certain  deductions and credits claimed by the Company on its federal income tax
returns for the years 1981 through 1989.  The Revenue  Agents'  Reports  reflect
proposed adjustments to the Company's federal income tax returns for this period
which, if sustained,  would give rise to tax deficiencies totaling approximately
$227  million.  The  Company  believes  that any such  deficiencies  as  finally
determined would be significantly  less than the amounts proposed in the Revenue
Agents' Reports. The Revenue Agents have

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<PAGE>



also  proposed  ITC  adjustments  which,  if  sustained,  would  reduce  the ITC
carryforwards  by approximately  $96 million.  The Company has protested some of
the  proposed  adjustments  which are  presently  under  review by the  Regional
Appeals Office of the Internal Revenue  Service.  If this review does not result
in a settlement that is satisfactory to the Company, the Company intends to seek
a judicial review.  The Company believes that its reserves are adequate to cover
any tax  deficiency  that  may  ultimately  be  determined  and that  cash  from
operations will be sufficient to satisfy any settlement reached.


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NOTE 10. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

The Company has entered into substantial  commitments for gas supply,  purchased
power and transmission  facilities.  The costs associated with these commitments
are recovered from customers through provisions in the Company's rate tariffs.

The  Company  expended  approximately  $1  million  in 1995  to meet  continuous
emission  monitoring  requirements  and to meet  Phase I  nitrogen  oxide  (NOx)
reduction  requirements  under the  federal  Clean  Air Act  (CAA).  Subject  to
requirements that are expected to be promulgated in forthcoming regulations, the
Company  estimates  that it may be  required to expend  approximately  $50 to 60
million  (net of NOx  credit  sales) by 2003 to meet  Phase II and Phase III Nox
reduction  requirements and  approximately $24 million by 1999 to meet potential
requirements for the control of hazardous air pollutants from power plants.  The
Company believes that all of the above costs will be recoverable through rates.

CONTINGENCIES

LONG ISLAND POWER AUTHORITY PROPOSED PLAN

During  1995,  the  Governor  of the State of New York  requested  that the Long
Island Power Authority  (LIPA) develop a plan that, in addition to replacing the
Company as the  primary  electric  and gas utility on Long  Island,  would among
other  things,  produce an electric  rate  reduction of at least 10%,  provide a
framework for long-term  competition in power  production  and protect  property
taxpayers on Long Island. In response to this request,  the Board of Trustees of
LIPA  established a committee  (Evaluation  Committee) to analyze  various plans
involving the Company's business operations and assets.

In December 1995, after soliciting  information and indications of interest from
various    parties   in   connection   with   a    LIPA-facilitated    financial
restructuring/acquisition   of  the  Company,  the  members  of  the  Evaluation
Committee  and their  advisors  announced  a proposed  plan to  restructure  the
Company and reduce  electric  rates on Long Island by 12% (Proposed  Plan).  The
Proposed  Plan,  which  has not  been  adopted  by the LIPA  Board  or  formally
presented to the  Company's  Board of  Directors  for  consideration,  generally
provides  that:  (i) the  Company  sell,  subject  to LIPA's  approval,  its gas
business and  electric  generation  assets;  (ii) LIPA  purchase  the  Company's
transmission,  distribution and  Shoreham-related  assets; (iii) LIPA enter into
long-term  power  purchase  agreements  with the  purchasers  of the  generation
assets;  (iv)  LIPA  enter  into  agreements  with  contractors  to  manage  the
transmission and distribution system; and (v) LIPA exercise its power of eminent
domain over all or a portion of the  Company's  assets or securities in order to
achieve its  objectives  if a  negotiated  agreement  cannot be reached with the
Company.

The Company has  indicated  to LIPA that certain  elements of the Proposed  Plan
raise  significant  concerns.   Specifically,  the  Proposed  Plan  contains  no
information  regarding  the  values  or prices  contemplated  to be paid for the
Company's assets, no financing commitments for any portion of the

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proposed  transaction  were disclosed and no indications  that  endorsements  by
certain State officials  required to approve any transaction  undertaken by LIPA
have been  obtained.  In addition,  based on the limited  information  currently
available, the Company is unable to determine how the anticipated rate reduction
would be achieved  and how the  reliability  of the electric  system,  including
storm restoration capabilities,  would be maintained given the multiple entities
that would be responsible for providing such service.

Notwithstanding  these  concerns,  the Company remains willing to cooperate with
LIPA  in  developing  a plan  that is  beneficial  to the  Company's  investors,
customers and employees.  The Company is  continuously  assessing  various other
strategies  in  an  effort  to  provide  the  greatest  possible  value  to  its
constituents  in  light  of the  changing  economic,  regulatory  and  political
challenges  affecting  the  Company.  Such  strategies  may include a review and
modification  of its  operations  to best meet the  challenges  of a competitive
environment,  a possible reorganization of the Company, potential joint ventures
and/or possible business combinations with other entities.

The implementation of certain plans involving the Company's business  operations
and assets would be subject to, among other things,  shareholder  and regulatory
approvals  and  could  impact  the  Company's  future   financial   results  and
operations.  Accordingly,  the Company is unable to determine what plan, if any,
will be pursued by it and/or  LIPA or whether any  related  transaction  will be
consummated.

COMPETITIVE ENVIRONMENT

The electric industry  continues to undergo  fundamental  changes as regulators,
elected officials and customers seek lower energy prices.  These changes,  which
may have a  significant  impact  on future  financial  performance  of  electric
utilities,  are being  driven  by a number of  factors  including  a  regulatory
environment in which traditional  cost-based  regulation is seen as a barrier to
lower energy prices. In 1995, both the Public Service Commission of the State of
New York (PSC) and the Federal Energy  Regulatory  Commission  (FERC)  continued
their  separate  initiatives  with  respect  to  developing  a  framework  for a
competitive electric marketplace.

New York State Competitive Opportunities Proceedings

In  1994,  the PSC  began  the  second  phase of its  Competitive  Opportunities
Proceedings  to  investigate  issues  related  to the  future of the  regulatory
process in an industry  which is moving  toward  competition.  The PSC's overall
objective was to identify regulatory and ratemaking  practices that would assist
New York State  utilities in the  transition to a more  competitive  environment
designed to increase efficiency in providing electricity while maintaining safe,
affordable and reliable service.

During  1995,  the  proceedings  continued  with the PSC  adopting  a series  of
principles  which it will use to guide the  transition  of the electric  utility
industry  in New York State  from a  rate-regulated  cost of service  model to a
competitive market-driven model. The principles state, among other things, that:
(i)  consumers  should have a  reasonable  opportunity  to realize  savings from
competition; (ii) a basic level of reasonably priced service must be maintained;
(iii) the integrity, safety and reliability of

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<PAGE>



the system should not be jeopardized;  and (iv) the current industry  structure,
in which most power  plants are  vertically  integrated  with  natural  monopoly
transmission and distribution  systems,  should be thoroughly examined to ensure
that it does not impede or obstruct the  development  of effective  wholesale or
retail competition. In addition, the principles state that utilities should have
a reasonable  opportunity  to recover  prudent and verifiable  expenditures  and
commitments  made  pursuant to their legal  obligations,  consistent  with these
principles.

In October 1995, the Energy  Association,  which is comprised of the Company and
the six other investor-owned New York State utilities, filed a proposal designed
to achieve the principles  outlined by the PSC. The proposal,  which is referred
to as the  "Wholesale  Poolco  Model",  establishes a framework  that will allow
competition  at the wholesale  level.  The plan would,  among other things:  (i)
allow  utilities,  non-regulated  generators  and other market  participants  to
create a wholesale  exchange that allows market forces to determine the price of
wholesale  electricity;  (ii) establish an Independent  System Operator (ISO) to
coordinate  the safe and  reliable  operation  of the  bulk  power  transmission
system;  (iii) increase  customer choice by providing clear market price signals
so customers can make  informed  decisions on the use of  electricity;  and (iv)
separate  the  generation  portion of a utility's  business  from its  regulated
transmission and distribution business.

In this model,  competing  generating  suppliers would bid energy sales into the
market.  The market  clearing price for energy would be determined by the bid of
the  highest  price  unit  needed  to serve the load in a  particular  location.
Regulated utility  companies could purchase energy from the market,  which would
establish  a half-hour  locational  spot market  price for  electricity,  or the
utility could seek to enter into bilateral energy agreements with other parties.
Bilateral  agreements  would  be  administered  independently  of the  wholesale
exchange,  but would be scheduled  through the ISO. These  bilateral  agreements
would be permitted  among  utility  companies,  generating  companies  and power
marketers. In the Wholesale Poolco Model, the purchase of electricity by end use
customers would still be bundled with  transmission,  distribution  and customer
service, all of which would be provided by regulated utilities.

The support of the New York State  utilities for the  Wholesale  Poolco Model is
predicated on a number of factors,  including:  (i) a reasonable  opportunity to
fully recover all investments and expenditures  made to provide reliable service
under the existing regulatory  compact;  (ii) PSC support for the option of each
utility to continue in the  generation  business;  (iii)  special  treatment  of
nuclear plants based on their unique characteristics; and (iv) the adoption of a
clearly defined transition plan to ensure that the interests of the customer and
the investor are adequately protected.

In  December  1995,  an  Administrative  Law  Judge  (ALJ)  of the PSC  issued a
Recommended   Decision  (RD)  to  the  PSC  with  respect  to  this  Competitive
Opportunities  Proceedings.  The ALJ recommended a competitive model which seeks
to  transition  the electric  utility  industry in New York State to full retail
competition through two stages. The first stage of this recommendation  seeks to
transition  the industry  from its current cost of service rate  regulation to a
competitive  wholesale model similar to the Wholesale  Poolco Model.  This first
stage would allow participants to

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<PAGE>



become  familiar with the  operation of a  deregulated,  competitive  generation
market prior to the eventual  movement to full retail  competition in the second
stage, through a model known as the Flexible Retail Poolco Model.

The Flexible Retail Poolco Model contains many of the same attributes associated
with the Wholesale  Poolco Model,  including:  (i) an ISO to coordinate the safe
and reliable  operation of generation and transmission;  (ii) open access to the
transmission   system,   which  would  be  regulated  by  FERC;  and  (iii)  the
continuation  of a regulated  distribution  company to operate and  maintain the
distribution  system.  The  principal  difference  between  the  models  is that
customers  would have a choice among  suppliers of  electricity  in the Flexible
Retail Poolco Model whereas in the Wholesale  Poolco Model, the regulated entity
would acquire electric energy from the spot energy sales exchange to sell to the
customer.

The Flexible  Retail  Poolco Model would also:  (i)  deregulate  energy/customer
services such as meter reading and customer billing;  (ii) unbundle  electricity
into   four   components:    generation,    transmission,    distribution,   and
energy/customer  services;  and  (iii)  provide  customers  with a choice  among
suppliers of electricity,  and allow customers to acquire  electricity either by
long-term contracts or purchases on the spot market or a combination of the two.

One of the most contentious issues of the Competitive  Opportunities Proceedings
has been the position  taken by the various  parties to the  proceedings  on the
amount of recovery  utilities  should be permitted to collect from customers for
so-called  stranded  investments.  Stranded  investments  represent  costs  that
utilities would have otherwise recovered through rates under traditional cost of
service regulation that, under competition, utilities may not be able to recover
since the market  price for their  product may be  inadequate  to recover  these
costs.  The Staff of the PSC, for example,  has indicated that utilities  should
not expect full recovery of stranded costs. The Energy Association has commented
that  utilities  have a sound legal  precedent  confirmed by  long-standing  PSC
policy to fully recover all prudently incurred costs,  including stranded costs.
The RD states that for recovery,  stranded costs must be prudent, verifiable and
unable to be reduced through mitigation measures. The RD states that recovery of
stranded  costs be predicated on the prudency of the costs  incurred.  The costs
must be  verifiable  and the  Company  must  show  that it was  unable  to avoid
incurring these costs.

The RD states that a generic decision should address the definition,  the method
of  measurement,   the  requirements  for  mitigation,   a  preferable  recovery
mechanism,  and a  standard  for  the  recovery  of  stranded  investments.  The
calculation of the amount to be recovered  from  customers,  however,  should be
left to individual  rate cases or special  proceedings  that should begin during
1996.  The RD  further  directs  New  York  State  investor-owned  utilities  to
individually  file,  within  six  months of the  PSC's  order,  a  comprehensive
long-term proposal addressing the significant components of the RD.

It is not possible to predict the  ultimate  outcome of these  proceedings,  the
timing thereof,  or the amount, if any, of stranded costs that the Company would
recover in a competitive  environment.  The outcome of these  proceedings  could
adversely  affect  the  Company's   ability  to  apply  Statement  of  Financial
Accounting Standards (SFAS) No. 71, "Accounting for the

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Effects  of Certain  Types of  Regulation",  which,  pursuant  to SFAS No.  101,
"Accounting for Discontinuation of Application of SFAS No. 71" and SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed  Of," could then require a  significant  write-down  of assets,  the
amount of which cannot presently be determined. For a further discussion of SFAS
No. 71 and SFAS No. 121, see Note 1.

The Electric Industry - Federal Regulatory Issues

As a result of Congress' passage of the Public Utility  Regulatory  Policies Act
of 1978 (PURPA),  and the National  Energy  Policy Act of 1992 (NEPA),  the once
monopolistic electric utility industry now faces competition.

PURPA's  goal is to  reduce  the  United  States'  dependence  on  foreign  oil,
encourage  energy  conservation  and  promote  diversification  of fuel  supply.
Accordingly,  PURPA  provided  for the  development  of a new class of  electric
generators which rely on either cogeneration  technology or alternate fuels. The
utilities are  obligated  under PURPA to purchase the output of certain of these
new generators, which are known as qualified facilities (QFs).

NEPA sought to increase economic  efficiency in the creation and distribution of
power by relaxing  restrictions on the entry of new competitors to the wholesale
electric  power  market  (i.e.,  sales to an entity for  resale to the  ultimate
consumer).  NEPA does so by creating exempt  wholesale  generators that can sell
power in wholesale markets without the regulatory  constraints placed on utility
generators  such as the Company.  NEPA also expanded  FERC's  authority to grant
access  to  utility  transmission  systems  to all  parties  who seek  wholesale
wheeling for  wholesale  competition.  Significant  issues  associated  with the
removal of restrictions on wholesale  transmission  system access have yet to be
resolved and the potential impact on the Company's financial position cannot yet
be determined.

FERC is in the  process  of setting  policy  which will  largely  determine  how
wholesale competition will be implemented. FERC has declared that utilities must
provide wholesale wheeling to others that is comparable to the service utilities
provide  themselves.  FERC has  issued  policy  statements  concerning  regional
transmission  groups,  transmission  information  requirements  and "good faith"
requests  for service and  transmission  pricing.  In March 1995,  FERC issued a
Notice  of  Proposed  Rulemaking  (NOPR)  which  combined  the  issues  of  open
transmission  access and stranded  cost  recovery.  The NOPR  contained a strong
endorsement of the right of the utilities to full recovery of stranded costs due
to wholesale wheeling and retail-turned-wholesale wheeling arrangements.  During
the year,  FERC has  followed up on these issues  through an  extensive  comment
period,  holding public hearings on pro-forma  transmission  tariffs,  ancillary
services,  real-time information systems and power pooling issues. FERC recently
announced its interest in exploring  the role of an ISO in providing  comparable
transmission  access.  It is expected that FERC will issue a final order on open
access in 1996. Utilities,  including the Company, and numerous other interested
parties are actively involved in these proceedings.

It is not possible to predict the outcome of these proceedings or the effect, if
any, on the financial condition of the Company.  The Company participates in the
wholesale electricity market primarily as a buyer, and

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in this  regard  should  benefit  if rules  are  adopted  which  result in lower
wholesale prices for its retail customers.

The Company's Service Territory

The changing utility regulatory environment has affected the Company in a number
of ways. For example,  PURPA's  encouragement of the non-utility generator (NUG)
industry has negatively impacted the Company. In 1995, the Company lost sales to
NUGs totaling 366 gigawatt-hours  (Gwh) representing a loss in electric revenues
net of  fuel  (net  revenues)  of  approximately  $28  million,  or  1.5% of the
Company's net revenues. In 1994, the Company lost sales to NUGs totaling 237 Gwh
or approximately $24 million of net revenues.  The increase in lost net revenues
resulted principally from the completion,  in April 1995, of a QF located at the
State University of New York at Stony Brook, New York (Stony Brook Project). The
annual  load  loss  due to this  QF is  estimated  to be 188  Gwh.  The  Company
estimates  that  in  1996,  sales  losses  to NUGs  will be 414 Gwh an  increase
reflecting 12 months of operation  for the Stony Brook Project or  approximately
1.7% of projected  net  revenues.  The Company  believes that load losses due to
NUGs  have  stabilized.  This  belief  is based on the fact  that the  Company's
customer  load  characteristics,  which lack a significant  industrial  base and
related  large   thermal  load,   will  mitigate  load  loss  and  thereby  make
cogeneration economically unattractive.

Additionally,  as mentioned  above,  the Company is required to purchase all the
power offered by QFs which in 1995 and 1994 approximated 205 megawatts (MW). QFs
have the choice of pricing  sales to the  Company at either the PSC's  published
estimates of the  Company's  long-range  avoided  costs (LRAC) or the  Company's
tariff  rates,  which are modified from time to time,  reflecting  the Company's
actual avoided costs.  Additionally,  until repealed in 1992, New York State law
set a minimum price of six cents per  kilowatt-hour  (kWh) for utility purchases
of power  from  certain  categories  of QFs,  considerably  above the  Company's
avoided  cost.  The six cent minimum now only applies to contracts  entered into
before June 1992. The Company  believes that the repeal of the six cent minimum,
coupled  with recent PSC updates  which  resulted in lower LRAC  estimates,  has
significantly reduced the economic benefits of constructing new QFs. The Company
estimates  that  purchases  from QFs  required by federal and state law cost the
Company $53 million more than it would have cost had the Company  generated this
power in both 1995 and 1994.

The Company  has also  experienced  a revenue  loss as a result of its policy of
voluntarily  providing  wheeling of New York Power  Authority  (NYPA)  power for
economic  development.  The Company  estimates  that in 1995 and 1994 NYPA power
displaced   approximately   429  Gwh  and  400  Gwh  of  annual   energy  sales,
respectively.  The net  revenue  loss  associated  with this  amount of sales is
approximately  $30 million or 1.6% of the  Company's  1995 net  revenues and $28
million or 1.5% of the  Company's  1994 net revenues.  Currently,  the potential
loss of additional  load is limited by conditions in the Company's  transmission
agreements with NYPA.

Aside from NUGs, a number of customer groups are seeking to hasten consideration
and implementation of full retail competition. For example, an energy consultant
has  petitioned  the PSC,  seeking  alternate  sources of power for Long  Island
school districts.  The County of Nassau has also petitioned the PSC to authorize
retail wheeling for all classes of electric

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customers in the county. In addition,  several towns and villages on Long Island
are    investigating    municipalization,    in   which    customers    form   a
government-sponsored  electric supply  company.  This is one form of competition
likely to  increase  as a result of NEPA.  The Town of  Southampton  and several
other towns in the Company's  service territory are considering the formation of
a  municipally  owned and  operated  electric  authority to replace the services
currently provided by the Company.  Suffolk County issued a request for proposal
from suppliers for up to 200 MW of power which the County would then sell to its
residential  and  commercial  customers.  The County has  awarded the bid to two
off-Long  Island  suppliers  and has requested the Company to deliver the power.
The Company has responded  that it does not believe the County is eligible under
present laws and regulations to purchase wholesale power and resell it to retail
customers,  and has declined to offer the requested retail wheeling service. The
Company's  geographic  location and the limited electrical  interconnections  to
Long  Island  serve to  limit  the  accessibility  of its  transmission  grid to
potential competitors from off the system.

The  matters  discussed  above  involve  substantial  social,  economic,  legal,
environmental and financial issues.  The Company is opposed to any proposal that
merely  shifts  costs  from one group of  customers  to  another,  that fails to
enhance the provision of least-cost,  efficiently-generated  electricity or that
fails to  provide  the  Company's  shareowners  with an  adequate  return on and
recovery of their  investment.  The Company is unable to predict what action, if
any, the PSC or FERC may take regarding any of these  matters,  or the impact on
the Company's  financial  condition if some or all of these matters are approved
or implemented by the appropriate regulatory authority.

Notwithstanding the outcome of the state or federal regulatory rate proceedings,
or any other state action,  the Company believes that, among other  obligations,
the State has a  contractual  obligation  to allow the  Company to  recover  its
Shoreham-related assets.

ENVIRONMENT

The Company is subject to federal,  state and local laws and regulations dealing
with  air and  water  quality  and  other  environmental  matters.  The  Company
continually  monitors its  activities  in order to determine  the impact of such
activities  on  the   environment   and  to  ensure   compliance   with  various
environmental laws. Except as set forth below, no material proceedings have been
commenced  or, to the  knowledge of the Company,  are  contemplated  against the
Company  with  respect  to  any  matter   relating  to  the  protection  of  the
environment.

The New  York  State  Department  of  Environmental  Conservation  (NYSDEC)  has
required  the Company and other New York State  utilities  to  investigate  and,
where  necessary,  remediate  their former  manufactured  gas plant (MGP) sites.
Currently,  the  Company  is the owner of six  pieces of  property  on which the
Company or certain of its  predecessor  companies  is believed to have  produced
manufactured  gas. The Company expects to enter into an  Administrative  Consent
Order (ACO) with the NYDEC in 1996  regarding the  management  of  environmental
activities  at these  properties.  Although  the exact  amount of the  Company's
clean-up   costs,   cannot  yet  be   determined,   based  on  the  findings  of
investigations at two of these six sites, preliminary estimates indicate that it
will cost approximately $35 million

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to clean up all of these sites over the next five to ten years. Accordingly, the
Company had  recorded a $35 million  liability  and a  corresponding  regulatory
asset to reflect its belief that the PSC will provide for the future recovery of
these  costs  through  rates as it has for other New York State  utilities.  The
Company has notified its former and current insurance  carriers that it seeks to
recover from them certain of these  investigation  and clean-up costs.  However,
the Company is unable to predict the amount of insurance recovery,  if any, that
it may obtain.  In addition,  there are several other sites within the Company's
service territory that were former MGP sites.  Research is underway to determine
their  relationship,  if  any,  to the  Company  or its  predecessor  companies.
Operations  at these  facilities  in the late  1800's and early  1900's may have
resulted in the disposal of certain waste products on these sites.

The Company has been notified by the Environmental  Protection Agency (EPA) that
it is one of many potentially  responsible parties (PRPs) that may be liable for
the remediation of three licensed treatment, storage and disposal sites to which
the Company may have shipped waste products and which have  subsequently  become
environmentally   contaminated.   At  one   site,   located   in   Philadelphia,
Pennsylvania,  and operated by Metal Bank of America, the Company and nine other
PRPs, all of which are public  utilities,  have entered into an ACO with the EPA
to conduct a Remedial  Investigation and Feasibility Study (RI/FS).  Under a PRP
participant  agreement,  the  Company  is  responsible  for  8.2%  of the  costs
associated  with this RI/FS  which has been  completed  and is  currently  being
reviewed by the EPA. The Company's total share of costs to date is approximately
$0.5 million.  The level of remediation required will be determined when the EPA
issues  its  decision.  Based on  information  available  to date,  the  Company
currently anticipates that the total cost to remediate this site will be between
$14  million and $30  million.  The  Company  has  recorded a liability  of $1.1
million  representing  its estimated  share of the additional  cost to remediate
this site.

With respect to the other two sites,  located in Kansas City,  Kansas and Kansas
City,  Missouri,  the  Company  is  investigating  allegations  that it had made
agreements for disposal of polychlorinated  biphenyls (PCBs) or items containing
PCBs at these sites. The EPA has provided the Company with documents  indicating
that the Company  was  responsible  for less than 1% of the total  weight of the
PCB-containing  equipment,  oil and materials  that were shipped to the Missouri
site. The EPA has not yet completed compiling documents for the Kansas site. The
Company is  currently  unable to  determine  its share,  if any,  of the cost to
remediate  these two sites or the  impact,  if any, on the  Company's  financial
position.

In addition,  the Company was notified  that it is a PRP at a Superfund  Site in
Farmingdale,  New York.  Portions of the site are  allegedly  contaminated  with
PCBs,  solvents and metals.  The Company was also notified by other PRPs that it
should be responsible for expenses in the amount of  approximately  $0.1 million
associated with removing PCB-contaminated soils from a portion of the site which
formerly  contained  electric  transformers.  The Company is currently unable to
determine its share of the cost to remediate this site or the impact, if any, on
the Company's financial position.

The Connecticut  Department of  Environmental  Protection  (DEP) and the Company
have signed an ACO which will require the Company to address leaks

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from an electric  transmission  cable located under the Long Island Sound (Sound
Cable).  The Sound Cable is jointly  owned by the  Company  and the  Connecticut
Light and Power Company, a subsidiary of Northeast Utilities.  Specifically, the
order  requires the Company to evaluate  existing  procedures  and practices for
cable maintenance, operations and fluid spill response procedures and to propose
alternatives  to  minimize  fluid  spill  occurrences  and  their  impact on the
environment.   Alternatives  to  be  evaluated  range  from  improving  existing
monitoring  and  maintenance  practices to removal and  replacement of the Sound
Cable.  The Company is currently  unable to determine the costs it will incur to
complete  the  requirements  of the ACO or to  comply  with any  additional  DEP
requirements.

In addition,  the Company has been served with a subpoena from the U.S. Attorney
for the District of Connecticut to supply certain written information  regarding
releases of fluid from the Sound  Cable,  as well as  associated  operating  and
maintenance practices. Since the investigation is in its preliminary stages, the
Company is unable to determine  the  likelihood of a criminal  proceeding  being
initiated at this time. However, the Company believes all activities  associated
with the response to releases  from the Sound Cable were  consistent  with legal
and regulatory requirements.

The  Company  believes  that all  significant  costs  incurred  with  respect to
environmental  investigations  and  remediation  activities  will be recoverable
through rates.

NUCLEAR PLANT INSURANCE

The NRC requires the owners of nuclear  facilities to maintain  certain types of
insurance. For property damage at each nuclear generating site, the NRC requires
a minimum of $1.06  billion of coverage.  With respect to third party  liability
and property damage, the NRC requires nuclear plant owners to carry $200 million
in  primary  coverage.  Pursuant  to these  requirements,  the  Company  carries
property   insurance  and  third-party  bodily  injury  and  property  liability
insurance for its 18% share in NMP2.  The annual  premiums for this coverage are
not material.

The third-party  liability and property damage  insurance  policies also include
retroactive  premiums under certain  circumstances.  The retroactive  premium is
related to the NRC's  requirement that nuclear  facility owners,  in addition to
carrying  $200  million in primary  coverage,  also  participate  in a Secondary
Financial  Protection Fund (Fund). Under the Price Anderson Act, that assessment
related to the Fund could be up to $79.3 million per nuclear incident in any one
year at any nuclear unit,  but not in excess of $10 million in payments per year
for each incident.  The Price Anderson Act also limits liability for third-party
bodily  injury  and  third-party  property  damage  arising  out  of  a  nuclear
occurrence at each unit to $8.9 billion.  The Company is liable for its share of
any retroactive premium assessment levied against the NMP2 owners.

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NOTE 11. SEGMENTS OF BUSINESS

Identifiable  assets by segment  include net utility plant,  regulatory  assets,
materials and supplies,  accrued  unbilled  revenues,  gas in storage,  fuel and
deferred  charges.  Assets  utilized  for  overall  Company  operations  consist
primarily of cash and cash equivalents, accounts receivable and unamortized cost
of issuing securities.

<TABLE>
<CAPTION>

                                            (In millions of dollars)
For year ended December 31                             1995           1994            1993
OPERATING REVENUES
<S>                                                  <C>              <C>          <C>
Electric                                             $  2,484         $  2,481     $  2,352
Gas                                                       591              586          529
Total                                                $  3,075         $  3,067     $  2,881
OPERATING EXPENSES (excludes federal income tax)
Electric                                             $  1,657         $  1,640     $  1,514
Gas                                                       478              500          427
Total                                                $  2,135         $  2,140     $  1,941
OPERATING INCOME (before federal income tax)
Electric                                             $    827         $    842     $    838
Gas                                                       113               85          102
Total operating income                                    940              927          940
AFC                                                       (7)              (7)          (7)
Other income and deductions                              (38)             (45)         (56)
Interest charges                                          476              500          534
Federal income tax                                        206              177          172
Net Income                                           $    303         $    302     $    297
DEPRECIATION AND AMORTIZATION
Electric                                             $    122         $    112     $    106
Gas                                                        23               19           16
Total                                                $    145         $    131     $    122
CONSTRUCTION AND NUCLEAR FUEL EXPENDITURES*
Electric                                             $    162         $    155     $    171
Gas                                                        84              125          134
Total                                                $    246         $    280     $    305
</TABLE>

* Includes  non-cash  allowance  for other  funds used during  construction  and
excludes Shoreham post-settlement costs.
                                              (In millions of dollars)
At December 31                         1995             1994           1993
IDENTIFIABLE ASSETS
Electric                               $  9,964       $ 10,264       $ 10,377
Gas                                       1,180          1,181            956
Total identifiable assets                11,144         11,445         11,333
Assets utilized for overall
 Company operations                       1,340          1,034          1,121
Total Assets                           $ 12,484       $ 12,479       $ 12,454


                                       103

<PAGE>



NOTE 12. QUARTERLY FINANCIAL INFORMATION
(Unaudited)

<TABLE>
<CAPTION>

           (In thousands of dollars except earnings per common share)
                                                                           1995                1994
OPERATING REVENUES
<S>                            <C>                                  <C>                <C>    
                               For the quarter ended March 31      $     791,188       $    872,143
                                                       June 30            653,824            626,310
                                                  September 30            875,794            913,440
                                                   December 31            754,322            655,414
OPERATING INCOME
                                For the quarter ended March 31      $     180,875       $    183,865
                                                       June 30            143,246            139,478
                                                  September 30            239,561            276,965
                                                   December 31            167,936            144,637
NET INCOME
                                For the quarter ended March 31      $      70,299       $     69,620
                                                       June 30             41,392             24,787
                                                  September 30            131,221            168,872
                                                   December 31             60,374             38,573
EARNINGS FOR COMMON STOCK
                                For the quarter ended March 31      $      57,127       $     56,348
                                                       June 30             28,220             11,516
                                                  September 30            118,069            155,620
                                                   December 31             47,250             25,348
EARNINGS PER COMMON SHARE
                                For the quarter ended March 31      $         .48       $        .50
                                                       June 30                .24                .10
                                                  September 30                .99               1.32
                                                   December 31                .39                .21


</TABLE>


                                       104

<PAGE>



REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS

To the Shareowners and Board of Directors of Long Island Lighting Company

We have audited the  accompanying  balance sheet of Long Island Lighting Company
and the related statement of capitalization as of December 31, 1995 and 1994 and
the related  statements of income,  retained earnings and cash flows for each of
the three years in the period ended  December 31, 1995. Our audits also included
the  financial  statement  schedule  listed  in the index at Item  14(a).  These
financial  statements  and  schedule  are the  responsibility  of the  Company's
management.  Our  responsibility  is to express  an  opinion on these  financial
statements and schedule based on our audits.

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

In our opinion,  the financial  statements  referred to above present fairly, in
all material respects, the financial position of Long Island Lighting Company at
December 31, 1995 and 1994, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1995, in conformity
with generally accepted accounting principles. Also, in our opinion, the related
financial statement schedule, when considered in relation to the basic financial
statements  taken as a whole,  presents  fairly  in all  material  respects  the
information set forth therein.


Melville, New York
February 7, 1996

                                             /S/ Ernst & Young LLP  
                                             ---------------------  
                                                 Ernst & Young LLP  
                                             

                                       105

<PAGE>



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

Not applicable.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY

Information  required by Item 10 as to the Company's  Executive  Officers is set
forth  in Item 1,  "Business"  under  the  heading  "Executive  Officers  of the
Company" above.  Information  required by Item 10 as to the Company's  Directors
may be found in the Company's  proxy statement for its annual meeting to be held
on May 9, 1996 (the Annual Meeting). Such proxy statement is incorporated herein
by reference.

ITEM 11. EXECUTIVE COMPENSATION

Information  required by Item 11 may be found in the Company's  proxy  statement
for  the  Annual  Meeting.  Such  proxy  statement  is  incorporated  herein  by
reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information  required by Item 12 may be found in the Company's  proxy  statement
for  the  Annual  Meeting.  Such  proxy  statement  is  incorporated  herein  by
reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information  required by Item 13 may be found in the Company's  proxy  statement
for  the  Annual  Meeting.  Such  proxy  statement  is  incorporated  herein  by
reference.



                                     PART IV

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

(a)(1)   List of Financial Statements

         Statement  of Income for each of the three  years in the  period  ended
           December 31, 1995.

         Balance Sheet at December 31, 1995 and 1994.

         Statement  of  Retained  Earnings  for each of the  three  years in the
           period ended December 31, 1995.

         Statement of Capitalization at December 31, 1995 and 1994.


                                      106
<PAGE>


         Statement of Cash Flows for each of the three years in the period ended
           December 31, 1995.

         Notes to Financial Statements.

   (2)  List of Financial Statement Schedules

         Valuation and Qualifying Accounts (Schedule II)


                                      107
<PAGE>

   (3)  List of Exhibits

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

  3(a)   Restated Certificate of Incorporation of the Company dated November 11,
         1993 (filed as an Exhibit to the Company's Form 10-K for the Year Ended
         December 31, 1993.)

   (b)   By-laws of the  Company as amended on May 28, 1991 (filed as an Exhibit
         to the Company's Form 10-K for the Year Ended December 31, 1991.)

  4(a)   General and Refunding  Indenture  dated as of June 1, 1975 (filed as an
         Exhibit  to the  Company's  Form 10-K for the Year Ended  December  31,
         1991.)

         Twenty-seven  Supplemental  Indentures  to the  General  and  Refunding
         Indenture dated as of June 1, 1975, as follows:


                                            Previously Filed As An
                 Supplemental Indenture     Exhibit To The Company's

                 Number             Date             Form        Date
                 ------             ----             ----        ----
                 First              06/1/75          10-K        12/31/87
                 Second             09/1/75          10-K        12/31/87
                 Third              06/1/76          10-K        12/31/87
                 Fourth             12/1/76          10-K        12/31/87
                 Fifth              05/1/77          10-K        12/31/87
                 Sixth              04/1/78          10-K        12/31/87
                 Seventh            03/1/79          10-K        12/31/87
                 Eighth             02/1/80          10-K        12/31/87
                 Ninth              03/1/81          10-K        12/31/87
                 Tenth              07/1/81          10-K        12/31/87
                 Eleventh           07/1/81          10-K        12/31/87
                 Twelfth            12/1/81          10-K        12/31/87
                 Thirteenth         12/1/81          10-K        12/31/87
                 Fourteenth         06/1/82          10-K        12/31/87
                 Fifteenth          10/1/82          10-K        12/31/87
                 Sixteenth          04/1/83          10-K        12/31/87
                 Seventeenth        05/1/83          10-K        12/31/87
                 Eighteenth         09/1/84          10-K        12/31/87
                 Nineteenth         10/1/84          10-K        12/31/87
                 Twentieth          06/1/85          10-K        12/31/87
                 Twenty-first       04/1/86          10-K        12/31/87
                 Twenty-second      02/1/91          10-K        12/31/90
                 Twenty-third       05/1/91          10-K        12/31/91
                 Twenty-fourth      07/1/91          10-K        12/31/91
                 Twenty-fifth       05/1/92          10-K        12/31/92
                 Twenty-sixth       07/1/92          10-K        12/31/92
                 Twenty-seventh     06/1/94          10-K        12/31/94


                                       108

<PAGE>




     4(b)     Debenture  Indenture dated as of November 1, 1986 from the Company
              to The Connecticut Bank and Trust Company,  National  Association,
              as Trustee (filed as an Exhibit to the Company's Form 10-K for the
              Year Ended December 31, 1986).

              Seven Supplemental  Indentures to the Debenture Indenture dated as
              of November 1, 1986, filed as follows:

                                            Previously Filed As An
              Supplemental Indenture        Exhibit To The Company's
              ----------------------        ------------------------
              Number               Date      Form           Date
              ------               ----      ----           ----
              First                11/1/86   10-K           12/31/86
              Second               04/1/86   10-K           12/31/89
              Third                07/1/86   10-K           12/31/89
              Fourth               07/1/92   10-K           12/31/92
              Fifth                11/1/92   10-K           12/31/92
              Sixth                06/1/93   10-K           12/31/92
              Seventh              07/1/93   10-K           12/31/92

     4(c)     Debenture  Indenture dated as of November 1, 1992 from the Company
              to Chemical Bank, as Trustee (filed as an Exhibit to the Company's
              Form 10-K for the Year Ended December 31, 1992).

              Four Supplemental  Indentures to the Debenture  Indenture dated as
              of November 1, 1992, filed as follows:

                                            Previously Filed As An
              Supplemental Indenture        Exhibit To The Company's
              ----------------------        -----------------------
              Number               Date       Form          Date
              ------               ----       ----          ----
              First                01/1/93    10-K        12/31/92
              Second               03/1/93    10-K        12/31/92
              Third                03/1/93    10-K        12/31/92
              Fourth               03/1/93    10-K        12/31/92

10(a)   Sound Cable Project Facilities and Marketing Agreement dated as of
        August 26, 1987 between the Company and the Power Authority of the
        State of New York (filed as an Exhibit to the Company's  Form 10-K
        for the Year Ended December 31, 1987).

10(b)   Transmission Agreement by and between the Company and Consolidated
        Edison Company of New York, Inc. dated as of March 31, 1989 
        (filed as an Exhibit to the Company's Form 10-K for the Year Ended 
        December 31, 1989).

10(c)   Contract  for the sale of Firm Power and Energy by and between the
        Company  and the  State of New York  dated  as of April  26,  1989
        (filed as an Exhibit to the Company's Form 10-K for the Year Ended
        December 31, 1989).

10(d)   Capacity  Supply  Agreement  dated as of December 13, 1991 between
        the  Company  and the  Power  Authority  of the  State of New York
        (filed as an Exhibit to the Company's Form 10-K for the Year Ended
        December 31, 1991).

                                       109

<PAGE>




10(e)         Nine Mile Point Nuclear  Station Unit 2 Operating  Agreement dated
              as of January 1, 1993 by and between the  Company,  New York State
              Electric & Gas Corporation, Rochester Gas and Electric Corporation
              and  Central  Hudson  Gas and  Electric  Corporation  (filed as an
              Exhibit to the Company's Form 10-K for the Year Ended December 31,
              1993).

10(f)         Settlement  Agreement  on Issues  Related to Nine Mile Two Nuclear
              Plant  dated as of June 6, 1990 by and between  the  Company,  the
              Staff of the  Department of Public Service and others (filed as an
              Exhibit to the Company's Form 10-K for the Year Ended December 31,
              1990).

10(g)         Settlement Agreement -- LILCO Issues dated as of February 28, 1989
              by and  between the Company and the State of New York (filed as an
              Exhibit to the Company's Form 10-K for the Year Ended December 31,
              1988).

10(h)         Amended and Restated Asset  Transfer  Agreement by and between the
              Company and the Long Island Power  Authority  dated as of June 16,
              1988 as  amended  and  restated  on April  14,  1989  (filed as an
              Exhibit to the Company's Form 10-K for the Year Ended December 31,
              1989).

10(i)         Memorandum  of  Understanding  concerning  proposed  agreements on
              power  supply  for Long  Island  dated as of June 16,  1988 by and
              between the Company  and New York Power  Authority  as amended May
              24, 1989 (filed as an Exhibit to the  Company's  Form 10-K for the
              Year Ended December 31, 1989).

10(j)         Rate Moderation  Agreement  submitted by the staff of the New York
              State Public Service Commission on March 16, 1989 and supported by
              the Company  (filed as an Exhibit to the  Company's  Form 10-K for
              the Year Ended December 31, 1989).

10(k)         Site Cooperation and  Reimbursement  Agreement dated as of January
              24,  1990  by and  between  the  Company  and  Long  Island  Power
              Authority  (filed as an Exhibit to the Company's Form 10-K for the
              Year Ended December 31, 1989).

10(l)         Stipulation  of settlement  of federal  Racketeer  Influenced  and
              Corrupt  Organizations  Act Class Action and False  Claims  Action
              dated as of February 27, 1989 among the attorneys for the Company,
              the  ratepayer  class,  the  United  States  of  America  and  the
              individual  defendants  named therein  (filed as an Exhibit to the
              Company's Form 10-K for the Year Ended December 31, 1988).

10(m)         Revolving  Credit  Agreement  dated  as of June  27,  1989,
              between the Company and the banks and  co-agents  listed  therein,
              with the Exhibits  thereto  (filed as an Exhibit to the  Company's
              Form 10-K for the Year Ended  December 31, 1989) and as amended by
              the First  Amendment  dated as of October  13,  1989  (filed as an
              Exhibit to the Company's Form 10-K for the Year Ended December 31,
              1990) and as amended by the Second  Amendment dated as of March 5,
              1992 and as modified by a Waiver dated  November 5, 1992 (filed as
              an Exhibit to the Company's  Form 10-K for the Year Ended December
              31, 1992).

10(n)         Indenture of Trust dated as of December 1, 1989 by and between New
              York State Energy Research and Development Authority (NYSERDA) and
              The  Connecticut  National Bank, as Trustee,  relating to the 1989
              EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year
              Ended December 31, 1989).

              Participation  Agreement  dated  as of  December  1,  1989  by and
              between NYSERDA and the Company  relating to the 1989 EFRBs (filed
              as an  Exhibit  to the  Company's  Form  10-K for the  Year  Ended
              December 31, 1989).

10(o)         Indenture of Trust dated as of May 1, 1990 by and between  NYSERDA
              and The  Connecticut  National  Bank, as Trustee,  relating to the
              1990 EFRBs (filed as an Exhibit to the Company's Form 10-K for the
              Year Ended December 31, 1990).

              Participation  Agreement  dated as of May 1,  1990 by and  between
              NYSERDA  and the Company  relating to the 1990 EFRBs  (filed as an
              Exhibit to the Company's Form 10-K for the Year Ended December 31,
              1990).

10(p)         Indenture  of Trust  dated as of  January  1, 1991 by and  between
              NYSERDA and The Connecticut National Bank, as Trustee, relating to
              the 1991 EFRBs (filed as an Exhibit to the Company's Form 10-K for
              the Year Ended December 31, 1990).

              Participation Agreement dated as of January 1, 1991 by and between
              NYSERDA  and the Company  relating to the 1991 EFRBs  (filed as an
              Exhibit to the Company's Form 10-K for the Year Ended December 31,
              1990).

10(q)         Indenture  of Trust  dated as of  February  1, 1992 by and between
              NYSERDA  and IBJ  Schroder  Bank and Trust  Company,  as  Trustee,
              relating to the 1992  EFRBs,  Series A (filed as an Exhibit to the
              Company's Form 10-K for the Year Ended December 31, 1991).



                                      110
<PAGE>

              Participation  Agreement  dated  as of  February  1,  1992  by and
              between NYSERDA and the Company relating to the 1992 EFRBs, Series
              A (filed as an  Exhibit  to the  Company's  Form 10-K for the Year
              Ended December 31, 1991).

10(r)         Indenture  of Trust  dated as of  February  1, 1992 by and between
              NYSERDA  and IBJ  Schroder  Bank and Trust  Company,  as  Trustee,
              relating to the 1992  EFRBs,  Series B (filed as an Exhibit to the
              Company's Form 10-K for the Year Ended December 31, 1991).

              Participation  Agreement  dated  as of  February  1,  1992  by and
              between NYSERDA and the Company relating to the 1992 EFRBs, Series
              B (filed as an  Exhibit  to the  Company's  Form 10-K for the Year
              Ended December 31, 1991).

10(s)         Indenture  of Trust  dated as of  August  1,  1992 by and  between
              NYSERDA  and IBJ  Schroder  Bank and Trust  Company,  as  Trustee,
              relating to the 1992  EFRBs,  Series C (filed as an Exhibit to the
              Company's Form 10-K for the Year Ended December 31, 1992).

              Participation  Agreement dated as of August 1, 1992 by and between
              NYSERDA  and the  Company  relating  to the 1992  EFRBs,  Series C
              (filed as an Exhibit to the Company's Form 10-K for the Year Ended
              December 31, 1992).

10(t)         Indenture  of Trust  dated as of  August  1,  1992 by and  between
              NYSERDA  and IBJ  Schroder  Bank and Trust  Company,  as  Trustee,
              relating to the 1992  EFRBs,  Series D (filed as an Exhibit to the
              Company's Form 10-K for the Year Ended December 31, 1992).

              Participation  Agreement dated as of August 1, 1992 by and between
              NYSERDA  and the  Company  relating  to the 1992  EFRBs,  Series D
              (filed as an Exhibit to the Company's Form 10-K for the Year Ended
              December 31, 1992).

10(u)         Indenture  of Trust  dated as of  November  1, 1993 by and between
              NYSERDA and Chemical Bank, as Trustee, relating to the 1993 EFRBs,
              Series A (filed as an Exhibit to the  Company's  Form 10-K for the
              Year Ended December 31, 1993).

              Participation  Agreement  dated  as of  November  1,  1993  by and
              between NYSERDA and the Company relating to the 1993 EFRBs, Series
              A (filed as an  Exhibit  to the  Company's  Form 10-K for the Year
              Ended December 31, 1993).

10(v)         Indenture  of Trust  dated as of  November  1, 1993 by and between
              NYSERDA and Chemical Bank, as Trustee, relating to the 1993 EFRBs,
              Series B (filed as an Exhibit to the  Company's  Form 10-K for the
              Year Ended December 31, 1993).

              Participation  Agreement  dated  as of  November  1,  1993  by and
              between NYSERDA and the Company relating to the 1993 EFRBs, Series
              B (filed as an  Exhibit  to the  Company's  Form 10-K for the Year
              Ended December 31, 1993).

10(w)         Indenture  of Trust  dated as of  October  1, 1994 by and  between
              NYSERDA and Chemical Bank, as Trustee, relating to the 1994 EFRBs,
              Series A (filed as an Exhibit to the  Company's  Form 10-K for the
              Year Ended December 31, 1994).

              Participation Agreement dated as of October 1, 1994 by and between
              NYSERDA  and the  Company  relating  to the 1994  EFRBs,  Series A
              (filed as an Exhibit to the Company's Form 10-K for the Year Ended
              December 31 1994).

*10(x)        Indenture  of Trust  dated as of  August  1,  1995 by and  between
              NYSERDA and Chemical Bank, as Trustee, relating to the 1995 EFRBs,
              Series A.

                                      111
<PAGE>

              Participation  Agreement dated as of August 1, 1995 by and between
              NYSERDA and the Company relating to the 1995 EFRBs, Series A.

10(y)         Supplemental  Death and Retirement  Benefits Plan as amended
              and  restated  effective  May 1, 1995  (filed as an Exhibit to the
              Company's Form 10-Q for the Quarterly  Period Ended  September 30,
              1995) and related Trust Agreement, which Trust Agreement was filed
              as  Exhibit  10(q) to the  Company's  Form 10-K for the Year Ended
              December 31, 1990.

10(z)         Executive Agreements and Management Contracts

     (1)      Executive Employment Agreement dated as of January 30, 1984 by and
              between  William J.  Catacosinos  and the  Company,  as amended by
              amendments  dated  March  20,  1987  (filed as an  Exhibit  to the
              Company's  Form  10-K  for the  Year  Ended  December  31,  1986),
              December 22, 1989 (filed as an Exhibit to the Company's  Form 10-K
              for the Year Ended December 31, 1989), and December 2, 1991 (filed
              as an  Exhibit  to the  Company's  Form  10-K for the  Year  Ended
              December 31, 1991),  which  amendment was restated by an amendment
              dated as of December 2, 1991, and  amendments  dated as of May 31,
              1995 and August 4, 1995 (filed as Exhibits to the  Company's  Form
              10-Q for the  Quarterly  Period  Ended  September  30,  1995);  an
              Executive  Employment  Agreement dated as of August 4, 1995 (filed
              as an Exhibit to the Company's Form 10-Q for the Quarterly  Period
              ended September 30, 1995).

     (2)      Executive  Employment  Agreement  dated as of November 21, 1994 by
              and  between the Company  and  Theodore A.  Babcock,  (filed as an
              Exhibit to the Company's Form 10-K for the Year Ended December 31,
              1994)  which  agreement  is  substantially  the same as  Executive
              Employment  Agreement  by and between the Company and (1) James T.
              Flynn, (2) Joseph E. Fontana, (3) Robert X. Kelleher,  (4) John D.
              Leonard,  Jr.,  (5) Adam M. Madsen,  (6)  Kathleen A. Marion,  (7)
              Arthur  C.  Marquardt,  (8)  Brian R.  McCaffrey,  (9)  Joseph  W.
              McDonnell, (10) Leonard P. Novello dated as of April 1, 1995, (11)
              Anthony  Nozzolillo,   (12)  Richard  Reichler,  (13)  William  G.
              Schiffmacher,  (14) Robert B. Steger, (15) William E. Steiger, and
              (16) Edward J. Youngling.

     (3)      Indemnification  Agreement by and between the Company and Theodore
              A.  Babcock  dated as of February 23, 1994 (filed as an Exhibit to
              the  Company's  Form 10-K for the Year Ended  December 31,  1994),
              which  agreement  is  substantially  the  same as  Indemnification
              Agreement  by and between the Company and (1) James T. Flynn dated
              as of November 25, 1987, (2) Joseph E. Fontana dated as of October
              20, 1994,  (3) Robert X.  Kelleher  dated as of November 25, 1987,
              (4) John D. Leonard,  Jr. dated as of November 25, 1987,  (5) Adam
              M. Madsen dated as of November  25,  1987,  (6) Kathleen A. Marion
              dated as of May 30,  1990,  (7)  Arthur C.  Marquardt  dated as of
              January 21, 1991, (8) Brian R. McCaffrey  dated as of November 25,
              1987,  (9) Joseph W.  McDonnell  dated as of March 18, 1988,  (10)
              Leonard  P.  Novello  dated  as of  April 1,  1995,  (11)  Anthony
              Nozzolillo  dated as of July 29, 1992, (12) Richard Reichler dated
              as of September 30, 1993,  (13) William  Schiffmacher  dated as of
              November 25, 1987,  (14) Robert B. Steger dated as of February 20,
              1990, (15) William E. Steiger,  Jr. dated as of March 1, 1989, and
              (16) Edward J. Youngling dated as of November 4, 1988.

     (4)      Indemnification  Agreement by and between the Company and Vicki L.
              Fuller  dated as of January  3, 1994,  (filed as an Exhibit to the
              Company's  Form 10-K for the Year Ended  December  31, 1994) which
              agreement is substantially the same as  Indemnification  Agreement
              by and between the  Company  and (1) A. James  Barnes  dated as of
              January 31, 1992, (2) George Bugliarello dated as of May 30, 1990,
              (3) Renso L. Caporali  dated as of April 17, 1992,  (4) William J.
              Catacosinos  dated as of  November  19,  1987,  (5) Peter O. Crisp
              dated as of April 23,  1992,  (6)  Katherine D. Ortega dated as of
              April 20, 1993, (7) Basil A. Paterson dated as of November 19,
              1987, (8) Richard L. Schmalensee dated as of February 8, 1992, (9)
              George J.  Sideris  dated as of November  30,  1987,  

                                      112
<PAGE>

              (10) John H.  Talmage  dated as of  November  19,  1987,  and (11)
              Phyllis A. Vineyard dated as of November 19, 1987.

     (5)      Indemnification Agreement by and between the Company and Lionel M.
              Goldberg  dated as of April 20, 1993,  (filed as an Exhibit to the
              Company's Form 10-K for the Year Ended  December 31, 1993),  which
              agreement is substantially the same as Indemnification  Agreements
              by and  between the Company and Eben W. Pyne dated as of April 20,
              1993, and Winfield E. Fromm dated as of April 12, 1994.

     (6)      Long Island Lighting Company  Officers' and Directors'  Protective
              Trust  dated as of April 18,  1988 as Amended  and  Restated as of
              September  1,  1994  by  and  between  the  Company  and  Clarence
              Goldberg,  as Trustee  (filed as an Exhibit to the Company's  Form
              10-Q for the Quarterly period Ended September 30, 1994).

     (7)      Long Island Lighting Company's Retirement Plan for Directors dated
              as of February 2, 1990 (filed as an Exhibit to the Company's  Form
              10-K for the Year Ended December 31, 1989).

     (8)      Trust  Agreement for Officers  dated March 20, 1987 by and between
              the Company and Clarence  Goldberg as Trustee (filed as an Exhibit
              to the Company's Form 10-K for the Year Ended December 31, 1988).

     *(9)    Consulting  Agreement  dated as of May 24,  1995 by and between the
             Company and Winfield E. Fromm, which agreement is substantially the
             same as  Consulting  Agreements  dated  as of May  24,  1995 by and
             between the Company and Lionel M.
             Goldberg and Eben W. Pyne.

*23          Consent of Ernst & Young LLP, Independent Auditors.

*24(a)       Power  of  Attorney  executed  by  William  J.  Catacosinos,  dated
             February 9, 1996, which power of attorney is substantially the same
             as  powers of  attorney  executed  by (1) A.  James  Barnes,  dated
             February 11, 1996, (2) George Bugliarello, dated February 21, 1996,
             Renso L.  Caporali,  dated  February  9, 1996,  (4) Peter O. Crisp,
             dated  February 12, 1996,  (5) Vicki L. Fuller,  dated February 23,
             1996,  (6) Katherine D. Ortega,  dated February 23, 1996, (7) Basil
             A. Paterson,  dated February 23, 1996, (8) Richard L.  Schmalensee,
             dated February 10, 1996, (9) George L. Sideris,  dated February 11,
             1996,  (10) John H.  Talmage,  dated  February  9,  1996,  and (11)
             Phyllis S. Vineyard, dated February 23, 1996.

*24(b)       Certificate as to Corporate Power of Attorney.

 *24(c)      Certified   copy  of  Resolution  of  Board  of  Directors
             authorizing signature pursuant to Power of Attorney.

*27          Financial Data Schedule.

             Financial  Statements of subsidiary  companies accounted for by the
             equity method have been omitted  because such  subsidiaries  do not
             constitute significant subsidiaries.                               


(b)          Reports on Form 8-K                                                
                                                                                
             No reports on Form 8-K were filed in the fourth quarter of 1995. 
*Filed herewith.


                                      113
<PAGE>




                          LONG ISLAND LIGHTING COMPANY

                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS


                             (Thousands of Dollars)

<TABLE>
<CAPTION>


Column A                          Column B            Column C           Column D      Column E   
                                                     Additions 
                                                             Charged
                                   Balance at   Charged to   to other                  Balance at
Description                        beginning    costs and    accounts-    Deductions-     end of
                                   of period    expenses     describe     describe        period
<S>                                <C>               <C>                 <C>               <C>       
Year ended December 31, 1995 
Deducted from asset accounts:
               
Allowance for doubtful accounts    $23,365           $17,752             $16,441 (1)       $24,676
                                                                                        
Year ended December 31, 1994                                                            
Deducted from asset accounts:                                                           
                                                                                        
Allowance for doubtful accounts    $23,889           $19,542             $20,066 (1)       $23,365
                                                                                        
Year ended December 31, 1993                                                            
Deducted from asset accounts:                                                           
                                                                                        
Allowance for doubtful accounts     $24,375           $18,555             $19,041 (1)       $23,889
                                                                     
</TABLE>

(1) Uncollectible accounts written off, net of recoveries.


                                      114
<PAGE>
                                                




                                   Signatures


      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 and Title

                                      WILLIAM J. CATACOSINOS*
                                      William J. Catacosinos, Principal
                                      Executive Officer, President and
                                      Chairman of the Board of Directors

                                      /S/ JOSEPH E. FONTANA
                                      Joseph E. Fontana, Controller
                                      Principal Accounting Officer

                                      A. JAMES BARNES*
                                      A. James Barnes, Director

                                      GEORGE BUGLIARELLO*
                                      George Bugliarello, Director

                                      RENSO L. CAPORALI*
                                      Renso L. Caporali, Director

                                      PETER O. CRISP*
                                      Peter O. Crisp, Director

                                      VICKI L. FULLER*
                                      Vicki L. Fuller, Director

                                      KATHERINE D. ORTEGA*
                                      Katherine D. Ortega, Director

                                      BASIL A. PATERSON*
                                      Basil A. Paterson, Director

                                      RICHARD L. SCHMALENSEE*
                                      Richard L. Schmalensee, Director

                                      GEORGE J. SIDERIS*
                                      George J. Sideris, Director

                                      JOHN H. TALMAGE*
                                      John H. Talmage, Director


                                      PHYLLIS S. VINEYARD*
                                      Phyllis S. Vineyard, Director

                                      /S/ ANTHONY   NOZZOLILLO  
                                      Anthony  Nozzolillo
                                      (Individually,  as Senior  Vice  President
February 26, 1996                     and  Principal  Financial  Officer  and as
                                      attorney-in-fact  for each of the  persons
                                      indicated)

                                      115
<PAGE>



                                   SIGNATURES




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

                                          LONG ISLAND LIGHTING COMPANY



Date:  February 26, 1996                 By:    /s/ ANTHONY NOZZOLILLO
-----  -----------------                        -----------------------------
                                                    ANTHONY NOZZOLILLO
                                                    Principal Financial Officer


Original  powers  of  attorney,  authorizing  Kathleen  A.  Marion  and  Anthony
Nozzolillo, and each of them, to sign this report and any amendments thereto, as
attorney-in-fact  for each of the Directors  and Officers of the Company,  and a
certified  copy of the  resolution  of the  Board of  Directors  of the  Company
authorizing  said  persons and each of them to sign this  report and  amendments
thereto as  attorney-in-fact  for any Officers signing on behalf of the Company,
have been,  are being filed or will be filed with the  Securities  and  Exchange
Commission.

                                      116
<PAGE>