SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549


                                    FORM 10-K


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

                SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996

                                       OR

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

            OF THE SECURITIES EXCHANGE ACT OF 1934 [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 D, 4.25%         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 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
 7.85% Series Due 1999     7.90% Series Due 2008


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 certain of the other securities listed above are 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 December 31, 1996 was $2,672,275,023.  The aggregate market value
of Preferred Stock held by  non-affiliates  of the Company at December 31, 1996,
established  by Lehman  Brothers  based on the average bid and asked price,  was
$675,542,820.

  COMMON STOCK ($5 PAR) - SHARES OUTSTANDING AT DECEMBER 31, 1996: 120,780,792

      The  Company's  definitive  proxy  statement,  for its  Annual  Meeting of
Shareowners  to be held on May 8, 1997 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).


<PAGE>



                                Table of Contents


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

                                     PART I

ITEM 1.     BUSINESS....................................................  1
            The Company.................................................  1
            Territory...................................................  1
            Segments of Business........................................  1
            Employees...................................................  1
            Regulation and Accounting Controls..........................  2
            Merger Agreement with The Brooklyn Union Gas Company........  2
            Competitive Environment.....................................  4
            Electric Operations.........................................  5
                 General................................................  5
                 System Requirements, Energy Available and Reliability..  6
                 Energy Sources.........................................  6
                     Oil  ..............................................  6
                     Natural Gas........................................  7
                     Nuclear............................................  7
                     Purchased Power....................................  7
                     Interconnections...................................  8
                 Conservation Services..................................  8
                 The 1989 Settlement....................................  8
                 Electric Rates.........................................  8
            Gas Operations..............................................  9
                 General................................................  9
                 Gas System Requirements................................  9
                     Peak Day Capability................................ 10
                     Transportation .................................... 10
                     Storage............................................ 10
                     Cogen/IPP Deliveries............................... 10
                     Peak Shaving....................................... 11
                     Firm Gas Supply.................................... 11
                 Gas Rates.............................................. 11
                 Recovery of Transition Costs........................... 11
                 Natural Gas Vehicles................................... 12
            Environmental Matters....................................... 12
                 General................................................ 12
                 Air ................................................... 13
                 Water.................................................. 15
                 Land................................................... 16
                 Nuclear Waste.......................................... 20
            The Company's Securities.................................... 21
                 General................................................ 21
                 The G&R Mortgage....................................... 21
                 Unsecured Debt......................................... 22
                 Equity Securities...................................... 22
                     Common Stock....................................... 22
                     Preferred Stock.................................... 23
                     Preference Stock................................... 23
            Executive Officers of the Company........................... 23
            Capital Requirements, Liquidity and Capital Provided........ 28

ITEM 2.     PROPERTIES.................................................. 29

ITEM 3.     LEGAL PROCEEDINGS........................................... 29
            Shoreham.................................................... 29
            Environmental............................................... 30
            Human Resources............................................. 31
            Other Matters............................................... 32

ITEM 4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 33

                                     PART II

ITEM 5.     MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
            STOCKHOLDER MATTERS......................................... 34

                                        i

<PAGE>




ITEM 6.     SELECTED FINANCIAL DATA..................................... 35

ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
            AND RESULTS OF OPERATIONS................................... 40

ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 66
            Balance Sheet............................................... 67
            Statement of Income......................................... 69
            Statement of Cash Flows..................................... 70
            Statement of Retained Earnings.............................. 71
            Statement of Capitalization................................. 71
            Notes to Financial Statements............................... 73
            Report of Independent Auditors............................. 111

ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
            AND FINANCIAL DISCLOSURES...................................112

                                    PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY............ 112

ITEM 11.    EXECUTIVE COMPENSATION..................................... 112

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
            MANAGEMENT................................................. 112

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............. 112

                                     PART IV

ITEM 14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
            FORM 8-K................................................... 113
                 List of Financial Statements.......................... 113
                 List of Financial Statement Schedules................. 113
                 List of Exhibits...................................... 114
                 Reports  on  Form  8-K................................ 119
                 SCHEDULE II .......................................... 120

SIGNATURES  ........................................................... 121



                                       ii

<PAGE>



                                  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
DOL.................... New York State Department of Law
DSM.................... Demand Side Management
Dth.................... Dekatherms (Approx. One Thousand Cubic Feet of Gas)
EFRBs.................. Electric Facilities Revenue Bonds
EMF.................... Electromagnetic Fields
EPA.................... United States Environmental Protection Agency
ERISA.................. Employee Retirement Income Security Act of 1974
FCA.................... Fuel Cost Adjustment
FERC................... Federal Energy Regulatory Commission
FMC.................... Fuel Moderation Component
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 (One Million kWh)
IC..................... Internal Combustion
IDRBs.................. Industrial Development Revenue Bonds
IERP................... Integrated Electric Resource Plan
IPP.................... Independent Power Producers
ISO.................... Independent System Operator
kWh.................... Kilowatt hour
LIPA................... Long Island Power Authority
LRAC................... Long-Range Avoided Costs
LRPP................... LILCO Ratemaking and Performance Plan
MDA.................... Municipal Distribution Agency
MGP.................... Manufactured Gas Plant
MW..................... Megawatts (One Million Watts)
NEPA................... National Energy Policy Act of 1992
NGV.................... Natural Gas Vehicle
NMP2................... Nine Mile Point Nuclear Power Station, Unit 2
NMPC................... Niagara Mohawk Power Corporation
NOPR................... Notice of Proposed Rulemaking
NRC.................... Nuclear Regulatory Commission
NUG.................... Non-Utility Generator
NUSCO.................. Northeast Utilities Service Company
NYPA................... New York Power Authority
NYPP................... New York Power Pool
NYSERDA................ New York State Energy Research and Development Authority
PCB.................... Polychlorinated Biphenyls
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
PURPA.................. Public Utility Regulatory Policies Act of 1978
QF..................... Qualified Facilities
RI/FS.................. Remedial Investigation and Feasibility Study
RMA.................... Rate Moderation Agreement
RMC.................... Rate Moderation Component
Shoreham............... Shoreham Nuclear Power Station
SFAS................... Statement of Financial Accounting Standards

                                       iii

<PAGE>



                                     PART I


ITEM 1.  BUSINESS

THE COMPANY

Long  Island  Lighting  Company  (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 mailing address of the Company
is 175  East Old  Country  Road,  Hicksville,  New York  11801  and the  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  1996
estimate,  is 2.7 million persons,  including  approximately  98,000 persons who
reside  in  Queens  County  within  the City of New  York.  The 1996  population
estimate reflects a 0.7% increase since the 1990 census.

Approximately  80% of all workers  residing in Nassau and Suffolk  Counties  are
employed within the two counties. In 1996 total  non-agricultural  employment in
Nassau and Suffolk Counties  increased by  approximately  12,500  positions,  an
employment increase of 1.1%.

The Company  serves  approximately  1.03  million  electric  customers  of which
approximately 921,000 are residential. The Company receives approximately 49% of
its electric revenues from residential customers, 48% from commercial/industrial
customers  and 3% from  sales to other  utilities  and public  authorities.  The
Company also serves  approximately  460,000 gas customers,  412,000 of which are
residential, accounting for 61% of its 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,
1996; Item 6, "Selected Financial Data" and Notes 3 and 12 of Notes to Financial
Statements for the Year Ended December 31, 1996.

EMPLOYEES

As of December 31, 1996,  the Company had 5,413  full-time  employees,  of which
2,241 belong to Local 1049 and 1,292  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

                                        1

<PAGE>



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.
During  1996,  the Company  completed  the  implementation  of all  improvements
recommended in 1995 by the PSC as a result of their Internal  Control  Practices
audit.

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 accounting  jurisdiction,  the FERC
has jurisdiction over rates that the Company may charge for the sale of electric
energy for resale in interstate  commerce,  including  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 the FERC has  issued  two orders
relating to the development of competitive  wholesale  electric  markets.  For a
discussion  of these  FERC  Orders,  see Item 7,  "Management's  Discussion  and
Analysis of Financial  Condition and Results of  Operations"  for the Year Ended
December 31, 1996 under the heading "Competitive Environment." The 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).

MERGER AGREEMENT WITH THE BROOKLYN UNION GAS COMPANY

On December 29, 1996, the Company and The Brooklyn  Union Gas Company  (Brooklyn
Union)  entered  into  an  Agreement  and  Plan  of  Exchange   (Share  Exchange
Agreement), pursuant to which the companies will be merged in a transaction that
will result in the formation of a new holding company.  The new holding company,
which has not yet been named, will serve approximately 2.2 million customers and
have  revenues  of  more  than  $4.5  billion.  The  merger  is  expected  to be
accomplished through a tax-free

                                        2

<PAGE>



exchange of shares and accounted for as a pooling of interests.

The  description  of the Share  Exchange  Agreement  set forth  herein  does not
purport to be complete and is qualified in its entirety by the provisions of the
Share Exchange Agreement, filed as an exhibit to the Company's Current Report on
Form 8-K dated December 30, 1996.

The proposed  transaction,  which has been approved by both companies' boards of
directors,  would unite the  resources  of the  Company  with the  resources  of
Brooklyn Union. Brooklyn Union, with approximately 3,300 employees,  distributes
natural gas at retail,  primarily  in a territory  of  approximately  187 square
miles which  includes the boroughs of Brooklyn and Staten Island and  two-thirds
of  the  borough  of  Queens,   all  in  New  York  City.   Brooklyn  Union  has
energy-related  investments in gas exploration,  production and marketing in the
United  States and  Canada,  as well as energy  services  in the United  States,
including cogeneration products, pipeline transportation and gas storage.

Under the terms of the proposed  transaction,  the Company's common  shareowners
will receive .803 shares (the Ratio) of the new holding  company's  common stock
for each share of the Company's common stock that they currently hold.  Brooklyn
Union  common  shareowners  will  receive  one share of common  stock of the new
holding  company for each common share of Brooklyn  Union they  currently  hold.
Shareowners of the Company will own approximately 66% of the common stock of the
new holding company while Brooklyn Union shareowners will own approximately 34%.
The proposed  transaction will have no effect on either company's debt issues or
outstanding preferred stock.

The Share Exchange  Agreement  contains certain covenants of the parties pending
the consummation of the transaction.  Generally, the parties must carry on their
businesses  in the  ordinary  course  consistent  with  past  practice,  may not
increase  dividends on common stock  beyond  specified  levels and may not issue
capital stock beyond certain limits.  The Share Exchange Agreement also contains
restrictions  on, among other  things,  charter and by-law  amendments,  capital
expenditures,  acquisitions,  dispositions,  incurrence of indebtedness, certain
increases in employee  compensation  and benefits,  and affiliate  transactions.
Accordingly,  the  Company's  ability  to engage in certain  activity  described
herein may be limited or prohibited by the Share Exchange Agreement.

Upon completion of the merger,  Dr. William J.  Catacosinos will become chairman
and chief executive  officer of the new holding  company;  Mr. Robert B. Catell,
currently  chairman and chief executive  officer of Brooklyn Union,  will become
president and chief operating officer of the new holding company. One year after
the closing, Mr. Catell will succeed Dr. Catacosinos as chief executive officer,
with Dr. Catacosinos  continuing as chairman.  The board of directors of the new
company will be composed of 15 members,  six from the Company, six from Brooklyn
Union and three additional persons  previously  unaffiliated with either company
and jointly selected by them.

                                        3

<PAGE>




The companies will continue their respective current dividend policies until the
closing,  consistent with the provisions of the Share Exchange Agreement.  It is
expected that the new holding company's dividend policy will be determined prior
to closing.

The merger is conditioned  upon, among other things,  the approval of the merger
by the holders of two-thirds of the  outstanding  shares of common stock of both
the  Company  and  Brooklyn  Union and the  receipt of all  required  regulatory
approvals.  The Company is unable to determine when or if all required approvals
will be obtained.

In 1995, the Long Island Power Authority  (LIPA),  an agency of the State of New
York (NYS), was requested by the Governor of NYS to develop a plan,  pursuant to
its authority  under NYS law, to provide an electric rate  reduction of at least
10%,  provide a framework  for long-term  competition  in power  production  and
protect property tax payers on Long Island.

The Share Exchange Agreement contemplates that discussions,  which are currently
in  progress,  will  continue  with  LIPA to  arrive  at an  agreement  mutually
acceptable to the Company, Brooklyn Union and LIPA, pursuant to which LIPA would
acquire certain assets or securities of the Company, the consideration for which
would inure to the benefit of the new holding company.  In the event that such a
transaction  is  completed,  the Ratio would become  .880.  In  connection  with
discussions  with LIPA,  LIPA has  indicated  that it may  exercise its power of
eminent domain over all or a portion of the Company's  assets or securities,  in
order to  achieve  its  objective  of  reducing  current  electric  rates,  if a
negotiated  agreement cannot be reached. The Company is unable to determine when
or if an agreement with LIPA will be reached,  or what action, if any, LIPA will
take if such an agreement is not reached.

COMPETITIVE ENVIRONMENT

A discussion  of the  competitive  issues the Company  faces  appears in Item 7,
"Management's  Discussion  and  Analysis of Financial  Condition  and Results of
Operations", and Note 11 of Notes to Financial Statements for
the Year Ended December 31, 1996.


                                        4

<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 1996 summer  capacity of the Company's steam
generation  facilities,  Internal  Combustion  (IC)  Units and other  generation
facilities as reported to the New York Power Pool (NYPP) in December 1996:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------

LOCATION OF UNITS        DESCRIPTION          FUEL          UNITS            MW

<S>                      <C>                  <C>             <C>         <C>
COMPANY OWNED

Northport, L.I.          Steam Turbine        Dual*            2            778
                                              Oil              2            754

Port Jefferson, L.I.     Steam Turbine        Dual*            1            191
                                              Oil              1            191

Glenwood, L.I.           Steam Turbine        Gas              2            218

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            279
                                              Oil             30          1,072

JOINTLY OWNED

NMP2 (18% Share)
Oswego, New York         Steam Turbine        Nuclear          1            206


OWNED BY THE NEW
YORK POWER AUTHORITY

Holtsville, L.I.         Combined Cycle       Dual*            1            142
                                                              --          -----
       Total                                                  55          4,326
                                                              ==          =====

--------------------------------------------------------------------------------
     *Dual - Oil or natural gas.
</TABLE>

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 was 4,077 Megawatts (MW) on August 4,
1995, representing 84% of the total available capacity of

                                        5

<PAGE>



4,873 MW on that day,  which  included 713 MW of firm  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 continues to
meet this NYPP requirement.

SYSTEM REQUIREMENTS, ENERGY AVAILABLE AND RELIABILITY

In 1996, system kilowatt hour (kWh) energy  requirements on the Company's system
were 0.5% lower than in 1995. The Company forecasts  increases of 1.5% and 2.6%,
relative to 1996's  experience in system energy  requirements for the years 1997
and 1998,  respectively.  For the period  1999-2008,  the Company  forecasts  an
average  annual  growth rate in system  energy  requirements  of 1.0%.  Based on
projections of peak demand for electric power the Company  believes it will need
to acquire  additional  generating or demand-side  resources starting in 1998 in
order to  maintain  satisfactory  electric  supply  reliability.  The  Company's
Integrated  Electric  Resource  Plan  (IERP),   issued  in  1996,  recommends  a
combination  of a peak  load  reduction  demand-side  management  program  and a
capacity  purchase as the most economical  method of meeting this need. The IERP
projects that additional  electric generating capacity will need to be installed
on Long Island to meet peak demand in the summer of 2001. It is anticipated that
such  additional  capacity  would be  acquired  through  a  competitive  bidding
process.

The  percentages  of  total  energy  available  by  type of  fuel  for  electric
operations for the years 1996, 1995 and 1994 were as follows:
<TABLE>
<CAPTION>
FUEL MIX                                               (BASED ON MW HOURS)
--------------------------------------------------------------------------------
                          1996                 1995                 1994
--------------------------------------------------------------------------------
<S>                        <C>                  <C>                  <C>
Oil                         24%                  17%                  25%
Natural Gas                 25                   36                   23
Nuclear (NMP2)               9                    7                    9
Purchased Power             42                   40                   43
--------------------------------------------------------------------------------
Total                      100%                 100%                 100%
================================================================================
</TABLE>

ENERGY SOURCES

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

OIL
The  availability  and cost of oil used by the  Company is  affected  by factors
beyond  its  control  such  as  the  international  oil  market,   environmental
regulations, conservation measures and the availability of alternative fuels. In
order to reduce the impact of the above

                                        6

<PAGE>



factors on the Company's  operations,  the Company, over the past several years,
has refitted the majority of its steam  generation  units  enabling them to burn
oil or natural gas,  whichever is more  economical and consistent  with seasonal
environmental requirements.  Oil consumption in barrels for the years 1996, 1995
and 1994  was 7.1  million,  5.2  million  and 7.5  million,  respectively.  The
Company's fuel oil is supplied principally by five suppliers.

NATURAL GAS
Eight of the  Company's  eleven steam  generating  units have the  capability of
burning  natural  gas.  Six of these  units are dual  fired and are  capable  of
burning  either oil or natural  gas.  This  enables the Company to burn the most
cost  efficient  fuel,  consistent  with  seasonal  environmental  requirements,
thereby reducing the Company's  generation costs. In 1996, the Company completed
the first of two planned  conversions to dual firing at its Port Jefferson Power
Station.  The second conversion has a projected completion date of May 1997. Gas
consumption for electric  generation in 1996 was 50.2 million  dekatherms  (Dth)
compared to 69.8 million Dth in 1995. In 1996 and 1995, 52% and 67% respectively
of the energy generated by the Company's steam and internal combustion units was
produced by burning natural gas.

NUCLEAR
The Company  holds an 18% interest in NMP2, an 1143 MW nuclear  generating  unit
near Oswego,  New York,  which is operated by Niagara  Mohawk Power  Corporation
(NMPC).  The cotenants of NMP2, in addition to the Company,  are NMPC (41%), New
York  State  Electric  & Gas  Corporation  (18%),  Rochester  Gas  and  Electric
Corporation  (14%) and Central Hudson Gas & Electric  Corporation  (9%).  During
1996,  NMP2 operated at 87.1% of its capacity,  including a scheduled  refueling
outage.  Excluding this outage,  the plant operated at 96.6% of capacity  during
the year.

PURCHASED POWER
The Company  strives to provide its customers  with the most  economical  energy
available  to keep  electric  rates as low as  possible.  Often,  this energy is
generated more  economically  at power plants within other electric  systems and
transmitted  to the  Company  through its  interconnections.  In  addition,  the
Company is required to purchase  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 196 MW of capacity to the Company in
1996.  Capacity  from these sources is expected to remain at  approximately  the
same level in 1997.

In 1996, 1995 and 1994,  IPPs,  cogenerators  and the NYPA  Holtsville  facility
provided  16.1%,  16.3%  and  13.5%,  respectively,  of the  total  energy  made
available  by the  Company.  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

                                        7

<PAGE>



customers is small.  Furthermore,  under federal law, the Company is required to
buy energy from qualified  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, 1996 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 that 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, 1996.

THE 1989 SETTLEMENT

In February  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, 1996.

ELECTRIC RATES

A  discussion  of  electric  rates  appears  in  Note 3 of  Notes  to  Financial
Statements for the Year Ended December 31, 1996.


                                        8

<PAGE>



GAS OPERATIONS

GENERAL

In 1996, the Company actively  participated in proceedings before the FERC in an
effort to  mitigate  any  adverse  impact that  filings by  interstate  pipeline
companies  might  have on the  Company's  gas  customers  as well as to  improve
operational tariffs.  The Company also actively  participated in the proceedings
before the PSC which established the framework for a new competitive natural gas
marketplace within the State of New York.

In response to changes in federal and state  regulations  that have  "unbundled"
traditional  pipeline services in order to promote competition in the gas supply
and gas services  market,  the Company  implemented its  NaturalChoice(sm)  firm
transportation  program in April 1996.  Under  NaturalChoice(sm),  customers may
purchase  natural  gas from  qualified  suppliers  other than the  Company.  The
Company continues to provide  NaturalChoice(sm)  customers with all gas services
provided to traditional  sales customers  except for the procurement and sale of
gas. These services include the local  transportation  of gas, meter reading and
billing,  equipment  maintenance and emergency  response.  The Company's  profit
margins have not been impacted by this new program as the Company  collects from
these  customers all costs  associated  with  providing  its service,  including
operating the gas system.

As of  December  31,  1996,  there were  approximately  1,400  NaturalChoice(sm)
customers with annual  requirements of approximately  2,110,000 Dth or 3% of the
Company's gas system requirements.

The Company continues to aggressively pursue non-traditional markets in order to
enhance earnings,  through the sale of its gas products and services off-system.
Revenue  from these  non-traditional  markets  increased  to  approximately  $46
million for 1996 compared to $24 million for 1995.

GAS SYSTEM REQUIREMENTS

The Company had 460,000  firm gas  customers  at December  31,  1996,  including
286,000 gas space heating  customers,  an increase of  approximately  20,000 gas
space heating customers over the past three years. The Company's  penetration in
the space heating market within its service territory is approximately 28%.

Total firm sales for 1996, when normalized for weather,  increased approximately
1.4% over 1995.  The maximum  daily  sendout  experienced  on the  Company's gas
system was 585,227 Dth on January 19, 1994,  representing  83% of the  Company's
per day capability at that time.  The  forecasted  maximum daily sendout for the
1996-97 winter season (November 1 - March 31) is  approximately  629,000 Dth, or
81% of the Company's per day capability.


                                        9

<PAGE>



PEAK DAY CAPABILITY

The Company has firm gas peak day capability in excess of its projected  1996-97
winter season gas customer and off-system sales requirements. Firm capability is
summarized in the following portfolio:
<TABLE>
<CAPTION>

------------------------------------------------------------------------------
                                                        Dth         % of
                                                     per day        Total
------------------------------------------------------------------------------

<S>                                                  <C>            <C>
Transportation                                       276,000         36%

Storage                                              301,000         39

Cogen/IPP Deliveries                                  72,000          9

Peak Shaving                                         123,000         16
------------------------------------------------------------------------------

Total                                                772,000        100%
==============================================================================
</TABLE>



TRANSPORTATION
The Company has available under firm contract  276,000 Dth per day of year-round
and  seasonal  pipeline  transportation  capacity  which  is  provided  by  four
interstate  pipeline companies  including the Iroquois Gas Transmission  System.
The Company, through its wholly owned subsidiary, LILCO Energy Systems, Inc., is
a general partner in the Iroquois pipeline with an equity share of 1%.

STORAGE
In order to meet higher  winter  demand,  the Company  also has  long-term  firm
market  area  storage  services  in the  Pennsylvania  and New York areas  which
provide a total  maximum  daily  supply  of  301,000  Dth per day,  with a total
capacity of 23,745,000 Dth for the winter period. Of these totals, 7,000 Dth per
day and a total  capacity of 1,211,000 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.  The Company has given a
notice of contract  termination  effective  March 31,  1997,  as the Company has
sufficient capacity to meet expected system requirements.

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 production area storage capacity in Louisiana and Mississippi. The
Company has no  incremental  firm  pipeline  transportation  capacity  for these
supplies.

COGEN/IPP DELIVERIES
The  Company  has  contract  rights  with NYPA to receive a total of 900,000 Dth
during any continuous  100-day  period  between  November 1 and March 31 of each
winter  season  at a daily  rate not to exceed  31,000  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.

                                       10

<PAGE>



Starting  in the  1996-97  winter,  the  Company  has  contract  rights with the
Brooklyn Navy Yard Cogen  facility to receive a total of  approximately  576,000
Dth during the  November 1 - March 31 period at a rate of  approximately  30,000
Dth per day.

In  addition,  the  Company  has the right to request  812,000 Dth in the winter
period from TBG Cogen  facility with the  obligation to return the 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  approximately  103,000 Dth per day to the peak-day  capability of
the  Company's  system.  In addition,  the Company has propane  facilities  that
produce  20,000  Dth  per  day of  peak  shaving  with  a  storage  capacity  of
approximately 100,000 Dth.

FIRM GAS SUPPLY
The Company has  approximately  212,000  Dth per day of firm  supplies  that are
transported under its firm pipeline  transportation  capacity.  About 83,000 Dth
per  day is  Canadian  and  129,000  Dth per day is  domestic.  Included  in the
long-term  firm Canadian gas is about 3,000 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 various  quantities of market priced gas in both the seasonal and
monthly  spot  markets  that  is  transported   under  firm  and   interruptible
transportation agreements.

The Company has entered into long-term  supply contracts at commodity rates that
are market based.  The Company has no fixed price supply  contracts.  Certain of
these  contracts  have minimum  annual take or pay  arrangements  and/or  annual
supply demand charges associated with them.

GAS RATES

A  discussion  of gas rate  matters  appears  in Note 3 of  Notes  to  Financial
Statements for the Year Ended December 31, 1996.

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 supply  contracts.  In order to
recover  transition costs,  pipeline companies must demonstrate to the 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

                                       11

<PAGE>



transition  costs,  the Company  estimates that it will be responsible for total
transition  costs of  approximately  $9 million.  As of December 31,  1996,  the
Company  has  collected  $8  million  of  these  transition  costs  from its gas
customers.

NATURAL GAS VEHICLES

An area being  pursued by the Company is the Natural Gas Vehicle  (NGV)  market.
Long  Island was  recently  designated  a Clean City by the U.S.  Department  of
Energy, increasing access to available federal funds. The Clean Cities Coalition
is a partnership of public and private entities,  committed to the promotion and
use of  alternate  fuel  vehicles.  In  addition  to  company-owned  NGV fueling
stations  in  Hicksville  and   Brentwood,   the   Metropolitan   Transportation
Authority/Long Island Bus completed construction of a fueling station capable of
refueling  their  entire  fleet.  Long  Island Bus will add over 120  compressed
natural gas buses to their existing  fleet by July 1997 and has contracted  with
the  Company  for the  supply  of the  required  gas  which is  estimated  to be
approximately 335,000 Dth per year when fully operational.

ENVIRONMENTAL MATTERS

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.

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 Resource Conservation and
Recovery  Act of 1976,  the federal  Toxic  Substances  Control Act, the federal
Clean Water Act (CWA), and the federal Clean Air Act (CAA).

Capital expenditures for environmental improvements and related studies amounted
to approximately  $2.4 million in 1996 and, based on existing  information,  are
expected  to be $1.9  million in 1997.  These  expenditures  do not  include the
approximately  $30  million  that the  Company  expects to spend for the cost of
conversions to dual firing  capability at the Port Jefferson Power Station which
are  also  an  essential  element  of  the  Company's  environmental  compliance
strategy.  It is not possible to ascertain with certainty if or when the various
required  governmental  approvals for which  applications have been made will be
issued, or whether, except as noted below, additional

                                       12

<PAGE>



facilities or modifications  of existing or planned  facilities will be required
or,  generally,  what effect  existing or future  controls may have upon Company
operations.  Except as set forth below and in Item 3 - "Legal  Proceedings,"  no
material  proceedings  have been  commenced or, to the knowledge of the Company,
are contemplated by any federal,  state or local agency against the Company, nor
is the Company a defendant in any material litigation with respect to any matter
relating to the protection of the environment.

RECOVERABILITY OF ENVIRONMENTAL COSTS

The Company believes that none of the  environmental  matters,  discussed below,
will have a material adverse impact on the Company's  financial  position,  cash
flows or results of  operations.  In  addition,  the Company  believes  that all
significant  costs  incurred  with respect to  environmental  investigation  and
remediation  activities,  not  recoverable  from  insurance  carriers,  will  be
recoverable through rates.

AIR

Federal,  state  and  local  regulations  affecting  new and  existing  electric
generating  plants govern  emissions of sulfur  dioxide (SO2),  nitrogen  oxides
(NOX),  particulate  matter,  and,  potentially in the future,  fine particulate
matter (aerosols of SO2), hazardous air pollutants and carbon dioxide (CO2).

SULFUR DIOXIDE REQUIREMENTS

The laws  governing  the  sulfur  content  of the fuel oil  being  burned by the
Company in compliance  with the United States  Environmental  Protection  Agency
(EPA) approved Air Quality State  Implementation  Plan (SIP) are administered by
the New York State Department of Environmental  Conservation  (DEC). 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 natural gas and oil with  acceptably  low levels of sulfur as boiler fuels.
These fuels also result in reduced  vulnerability to any future fine particulate
standards  implemented in the form of stringent  sulfur dioxide emission limits.
The Company's use of low sulfur fuels has resulted,  and will continue to result
in  approximately  70,000 excess SO2  allowances per year through the year 1999.
The Company applies the proceeds, resulting from sales of excess SO2 allowances,
as a reduction to the Rate  Moderation  Component  (RMC) balance,  as more fully
discussed in Note 3 of Notes to Financial Statements.

NITROGEN OXIDES REQUIREMENTS

Due to the Company's program of cost effective  emission  reductions,  including
the  optimization of natural gas firing ability at almost all the steam electric
generating  stations,  the  Company  had the  lowest  NOX  emissions  of all the
utilities in New York State in 1996 and 1995.

                                       13

<PAGE>



Since the Company's  generating  facilities  are located  within a CAA Amendment
designated  ozone  non-attainment  area,  they  are  subject  to  NOx  reduction
requirements which are being implemented in three phases.  Phase I was completed
in  1995,  Phase  II  and  Phase  III  will  be  completed  in  1999  and  2003,
respectively.

The Company is currently in compliance  with Phase I NOx reduction  requirements
and in 1996 spent approximately  $200,000 on Phase II reduction projects.  It is
estimated that additional  expenditures of less than $1 million will be required
to meet Phase II NOx reduction  requirements.  Subject to requirements  that are
expected to be  promulgated in forthcoming  regulations,  the Company  estimates
that it may be required to spend an  additional  $44 million by the year 2003 to
meet Phase III NOx reduction requirements.  These expenditures may be reduced if
further  contemplated  gas conversions to dual fired capability at the Company's
Northport facility are implemented.

CONTINUOUS EMISSION MONITORING

The Company  spent  $100,000  in 1996 for  software  upgrades to the  Continuous
Emissions   Monitoring  Systems  at  the  Company's  steam  electric  generating
stations.  Additional software and equipment upgrades, which are not expected to
exceed  approximately  $3 million,  may be  required  by 1999 at all  generating
facilities  in order  to meet EPA  requirements  under  development  for the NOx
allowance program.

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 1998.
Until such  determination is made by the EPA, the Company cannot fully ascertain
what,  if any,  costs  will  be  incurred  for  the  control  of  hazardous  air
pollutants.

However, after the expenditure of approximately $800,000 in 1996 and the planned
spending  of  $1.7  million  for  the  period   1997-1999,   for   electrostatic
precipitator upgrades, and with the maximization of clean burning natural gas as
the primary fuel, hazardous air pollutant  regulations,  if enacted,  should not
impose any additional control requirements for the Company's facilities.

CARBON DIOXIDE REQUIREMENTS

CO2  emissions  from the  Company's  plants have been reduced by 50% since 1989,
making the plants less vulnerable to future CO2 reduction requirements.


                                       14

<PAGE>



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,  has  contributed  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 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,  which were dormant during 1996, are in
the preliminary stages of discovery and their outcome is uncertain.

WATER

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 make any  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.

In 1996,  the Company  spent $1.2  million to upgrade its waste water  treatment
facilities and for other measures  designed to protect  surface and ground water
quality, and expects to spend an additional $1.0 million in the years 1997-2000.

LONG ISLAND SOUND TRANSMISSION CABLES

During 1996, the Connecticut Department of Environmental Protection (DEP) issued
a modification to an  Administrative  Consent Order (ACO)  previously  issued in
connection  with an  investigation  of an  electric  transmission  cable  system
located  under the Long Island Sound (Sound  Cable) that is jointly owned by the
Company and the Connecticut Light and Power Company  (Owners).  The modified ACO
requires the Owners to submit to the DEP and DEC a series of reports and studies
describing cable system condition, operation and repair practices,  alternatives
for cable improvements or replacement and environmental impacts

                                       15

<PAGE>



associated  with leaks of fluid into the Long Island Sound,  which have occurred
from time to time. The Company  continues to compile  required  information  and
coordinate the activities necessary to perform these studies and, at the present
time is unable to determine the costs it will incur to complete the requirements
of the modified ACO or to comply with any additional requirements.

Previously,  the U.S.  Attorney for the District of Connecticut had commenced an
investigation  regarding  occasional  releases of fluid from the Sound Cable, as
well as associated operating and maintenance practices. The Owners have provided
the U.S.  Attorney with all requested  documentation.  The Company believes that
all  activities  associated  with the response to  occasional  releases from the
Sound Cable were consistent with legal and regulatory requirements.

In  addition,  during  1996 the  Long  Island  Soundkeeper  Fund,  a  non-profit
organization,  filed a suit  against  the  Owners of the Sound  Cable in Federal
District  Court  in  Connecticut  alleging  that the  Sound  Cable  fluid  leaks
constitute unpermitted discharges of pollutants in violation of the CWA and that
such pollutants  present a threat to the environment and public health. The suit
seeks,  among  other  things,  injunctive  relief  prohibiting  the Owners  from
continuing to operate the Sound Cable in alleged  violation of the CWA and civil
penalties of $25,000 per day for each violation from each of the Owners.

In December 1996, a barge, owned and operated by a third party,  dropped anchor,
causing  extensive  damage to the Sound Cable and a release of dielectric  fluid
into the Long Island Sound.  Temporary  clamps and leak abaters have been placed
on the cables which have stopped the leaks. Permanent repairs are expected to be
undertaken in the late spring of 1997. The  preliminary  estimate of the cost of
these  repairs is $15 million.  The Company  intends to seek recovery from third
parties  for costs  incurred by the  Company as a result of this  incident.  The
timing and amount of recovery,  if any,  cannot yet be determined.  In addition,
the Owners  maintain  insurance  coverage  for the Sound Cable which the Company
believes will be sufficient to cover any repair costs.  In any event,  any costs
not  reimbursed by a third party or covered by insurance  will be shared equally
by the Owners.

LAND

Superfund  imposes  joint and  several  liability,  regardless  of  fault,  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 

                                       16

<PAGE>



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. A discussion of
these sites is set forth below.

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.  In December  1996, the Company
filed a complaint in the United States District Court for the Southern  District
of  New  York  against  14  of  the  Company's  insurers  which  issued  general
comprehensive  liability  (GCL) policies to the Company.  The Company is seeking
recovery  under the GCL policies for the costs incurred to date and future costs
associated  with the clean-up of the  Company's  former  manufactured  gas plant
(MGP) sites and Superfund  sites for which the Company has been named a PRP. The
Company is seeking a declaratory  judgment that the defendant insurers are bound
by the terms of the GCL  policies,  subject to the stated  coverage  limits,  to
reimburse  the  Company for the clean up costs.  The outcome of this  proceeding
cannot yet be determined.

SUPERFUND SITES

METAL BANK

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),  which has been
completed and is currently being reviewed by the EPA. Under a PRP  participation
agreement, the Company is responsible for 8.2% of the costs associated with this
RI/FS. 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  based  upon  its 8.2%
responsibility under the RI/FS.

SYOSSET

The Company  and nine other PRPs have been named in a lawsuit  where the Town of
Oyster Bay (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 dating
back to the early 1930's. In a

                                       17

<PAGE>



Record of Decision issued in September 1990, the EPA set forth a remedial design
plan,  the cost of which was  estimated  at $27  million.  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 nine other PRPs. 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 position, cash flows or results of operations.

PCB, INC.

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 company named 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 and certain soil areas outside the buildings are contaminated with
PCBs.

In 1994,  the EPA requested  certain of the large PRPs,  which  include  several
other utilities, 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. The EPA has 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 Company  intends to join a PRP
Group which includes other utilities which has been organized 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.

PORT WASHINGTON

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

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
remediation  expenses in the amount of  approximately  $100,000  associated with
removing  PCB-contaminated  soils  from a  portion  of the site  which  formerly
contained electric

                                       18

<PAGE>



transformers. The Company is currently unable to determine its share of costs of
remediation at this site.

MANUFACTURED GAS PLANT SITES

The DEC has  required  the  Company  and  other  New  York  State  utilities  to
investigate and, where necessary,  remediate their former 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.  Operations at
these  facilities  in the late 1800's and early 1900's may have  resulted in the
disposal of certain waste products located at these sites.

The  Company  has entered  into  discussions  with the DEC which may lead to the
issuance  of  one  or  more  ACOs  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  $51  million to  investigate  and  remediate  all of these  sites
through  the year 2006.  Accordingly,  the  Company  has  recorded a $35 million
liability  reflecting  the  present  value of the future  stream of  payments to
investigate  and  remediate  these sites.  The Company used a risk-free  rate of
7.25% to  discount  this  obligation.  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.

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.  Remediation  activities at this
site were  essentially  complete  at the end of 1996 at a cost of  approximately
$1.0 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.  If  additional  remediation  is  required,  the  Company
estimates that cleanup costs will not exceed $500,000. The Company has initiated
cost recovery  actions against the third parties it believes are responsible for
causing the cable leak, the outcome of which are uncertain.


                                       19

<PAGE>



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 million and $5 million.

NUCLEAR WASTE

LOW LEVEL RADIOACTIVE WASTE

The federal Low Level Radioactive  Waste Policy Amendment Act of 1985,  requires
states to arrange for the disposal of all low level  radioactive waste generated
within the state or, in the  alternative,  to contract for their  disposal at an
operating facility outside the state. As a result, New York State has stated its
intentions of developing an in-state  disposal  facility due to the large volume
of low level  radioactive  waste generated within the state and has committed to
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 not begin  operation  until 2001.  Low level  radioactive
waste  generated at NMP2 is currently  being disposed of at the Barnwell,  South
Carolina waste disposal facility which reopened in July 1995 to out-of-state low
level waste generators.

In the event that off-site storage becomes  unavailable  prior to 2001, 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 currently recovered in rates.

SPENT NUCLEAR FUEL

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 its  electric
customers.  It is  anticipated  that the DOE facility  may not be available  for
permanent  storage until at least 2010.  Currently,  all spent nuclear fuel from
NMP2 is stored at the NMPC site,  and  existing  facilities  are  sufficient  to
handle all spent nuclear fuel generated at NMP2 through the year 2010.


                                       20

<PAGE>



For  information  concerning  environmental   litigation,   see  Item  3  "Legal
Proceedings" under the heading Environmental.

THE COMPANY'S SECURITIES

GENERAL

The Company's securities are rated by Moody's Investors Service,  Inc., Standard
and Poor's,  Fitch Investors  Service,  L.P. and Duff & Phelps Credit Rating Co.
For information relating to the ratings of the Company's securities, see Item 7,
"Management's  Discussion  and  Analysis of Financial  Condition  and Results of
Operations" for the Year Ended December 31, 1996.

THE G&R MORTGAGE

The Company's General and Refunding  Indenture dated June 1, 1975 (G&R Mortgage)
is a lien upon  substantially  all of the Company's  properties.  Outstanding at
December 31, 1996 were approximately $1.5 billion of G&R Bonds.

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  $4.7 billion of additional  G&R Bonds based upon net earnings for
the 12 months ended  December 31, 1996 and an assumed  interest rate of 9.0% 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  $65  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 $1.1 billion.

Under the provisions of the G&R Mortgage,  the Company must also satisfy by June
30 of each year a Sinking Fund requirement which for the year ended December 31,
1996, is $25 million.  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 requirements of the G&R Sinking Fund.

The G&R Mortgage also contains 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

                                       21

<PAGE>



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, 1996, the amount of such cumulative  property additions  calculated pursuant
to the G&R Mortgage was  approximately  $10.1 billion,  including  approximately
$5.5  billion of  property  additions  attributable  to  Shoreham.  Also,  as of
December 31, 1996,  the amount of the  cumulative  provision  for  depreciation,
similarly  calculated,  was approximately $1.9 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, 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, 1996, there were approximately $2.3
billion of debentures outstanding.

As of December 31, 1996, the Company had outstanding  approximately $917 million
principal amount of promissory notes, comprised of: (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 Facilities 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, 1996.

EQUITY SECURITIES

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

                                       22

<PAGE>



the Company's  Restated  Certificate of  Incorporation  and the  availability of
retained earnings, future earnings and cash.

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  (Earnings  Ratio).  The  Company
currently  satisfies the Earnings Ratio and could issue up to approximately $714
million  of  preferred  stock at an  assumed  dividend  rate of  9.5%.  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.

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.

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  December
1996.  Dr.  Catacosinos,  66, a resident  of Mill Neck,  Long  Island,  earned a
bachelor of science

                                       23

<PAGE>



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
and the Business  Alliance  for a New New York,  and is 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.

Theodore A. Babcock: Vice President since January 1997, 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
with 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,  42, received a bachelor of science degree in accounting from Manhattan
College and a masters  degree in finance  from Iona  College.  Mr.  Babcock is a
member of the board of the Huntington Township Chamber Foundation.

Charles A. Daverio:  Vice President of The Energy  Exchange Group since December
1996.  Mr.  Daverio,  47, holds a bachelor of  engineering  degree in mechanical
engineering  from  Manhattan  College,  a master of science degree in industrial
engineering  from New York  University  and a master of business  administration
from New York  Institute  of  Technology.  He joined  the  Company in 1976 as an
Associate Engineer.  He held various supervisory and managerial positions in the
Nuclear Engineering  Department from 1979 through 1989. In 1990, he was assigned
Manager of Gas Supply and Planning and was given the  additional  responsibility
for Gas Operations in 1993. Mr. Daverio is the Company's  representative  on the
Iroquois Gas Transmission  System's Management  Committee and is on the Board of
the Iroquois Pipeline Operating Company. Mr. Daverio is a member of the board of
the Huntington Arts Council.

James T. Flynn:  President and member of the Company's  Board of Directors since
December 1996 and Chief Operating Officer since March 1994, Mr. Flynn joined the
Company in October 1986 as Vice President of Fossil Production. He also held the
positions of Group Vice President, Engineering and Operations and Executive Vice
President.   Before   joining  the   Company,   Mr.   Flynn,   63,  was  General
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:  Vice  President  since  January 1997 and  Controller  since
October 1994, Mr. Fontana joined the Company in December 1992 as

                                       24

<PAGE>



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 Company's  Chief  Accounting  Officer.  Mr.  Fontana is a
member of the American Institute of Certified Public Accountants. Before joining
the Company,  Mr. Fontana was a Senior Manager at the  international  accounting
firm of Ernst & Young LLP. Mr.  Fontana,  39, holds a bachelor of science degree
in  accounting  from  Westchester  State  College  and  is  a  Certified  Public
Accountant.  Mr.  Fontana  is a member of the board of the  Huntington  Township
Chamber Foundation.

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,  60, 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.  From 1980 to 1984,  Mr.  Leonard was the Vice President and
Assistant  Chief  Engineer  for  Design  and  Analysis  at the  New  York  Power
Authority.  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 64 and a Licensed  Professional  Engineer in the State of
New York.

Adam M. Madsen:  Vice President of Corporate and Strategic  Planning since 1984,
Mr.  Madsen,  60,  holds a  bachelors  degree  in  electrical  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

                                       25

<PAGE>



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,  42, has a bachelor  of science  degree in  business  and
finance from the State University of New York at Old Westbury.

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:  Senior Vice  President of Marketing and External  Affairs
since December 1996, 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.  In July  1992 he was  named  Vice  President  of
External Affairs. 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 Brook.  Dr.  McDonnell,  45, holds  bachelor of arts and master of
arts degrees in philosophy from the State  University of New York at Stony Brook
and a  doctoral  degree  in  communications  from  the  University  of  Southern
California.

Leonard P. Novello:  Senior Vice  President  since  December  1996,  and General
Counsel since he joined the Company in April 1995.  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,  and a member of the
Professional  Responsibility Committee of the Association of the Bar of the City
of
                                       26

<PAGE>



New York.  He is also a member of the  Executive  Committee of the CPR Institute
for Dispute Resolution. Mr. Novello, 56, has a bachelors 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,  48, 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 Tax Planning and
Related  Services since January 1997. Mr.  Reichler held the positions of Deputy
General  Counsel and Vice  President  of Financial  Planning  and Taxation  from
January 1995 through  December  1996 and  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 23 years.  Mr.  Reichler,  62,  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:  Senior  Vice  President  of  Customer  Relations  and
Information  Systems and Technology since December 1996, Mr.  Schiffmacher  held
the positions of Vice  President of Customer  Relations  from April 1994 through
November 1996 and Vice President of 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, 53, 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.

Werner J. Schweiger:  Vice President of Electric Operations since December 1996.
Mr.  Schweiger  joined the Company in 1981 and has held a number of positions in
Electric Operations, as well as in Engineering. Most recently, he was Manager of
Electric  Systems  Engineering  from  October 1995 through  November  1996.  Mr.
Schweiger,  37,  received his bachelors  degree in electrical  engineering  from
Manhattan  College and also holds a masters degree in Energy Management from the
New York Institute of Technology.
                                   
                                       27

<PAGE>



Richard M. Siegel:  Vice President of Information  Systems and Technology  since
December 1996.  Mr. Siegel held the position of Director of Information  Systems
and  Technology  from June 1995 to December  1996.  Mr.  Siegel,  50, joined the
Company in 1969 as an  Associate  Engineer and has held  progressive  management
positions in Electric Operations and Engineering,  including Manager of Electric
System Engineering and Manager of Electric System Operations. Mr. Siegel holds a
bachelor of electrical  engineering degree from the City College of New York and
a master of science degree in Industrial Management from the State University of
New York at Stony Brook. Mr. Siegel is a Licensed  Professional  Engineer in the
State of New York.

Robert B. Steger:  Senior Vice  President of Gas  Business  Unit since  December
1996,  Mr.  Steger held the positions of Vice  President of Electric  Operations
from April 1994 through  November 1996 and Vice  President of Fossil  Production
from  February  1990 through  March 1994. He joined the Company in 1963 and held
progressive  operating and engineering  positions  including Manager of Electric
Production-Fossil  from 1985 through 1989. Mr.  Steger,  60, 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,  53,  held the  position  of Vice  President  of  Engineering  and
Construction  from July 1990  through  March  1994.  During his career  with the
Company,  which began in 1968,  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.  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, he became Vice President
of Customer  Relations,  and from March 1993  through  March  1994,  he was Vice
President of Customer  Relations and Conservation.  Mr.  Youngling,  52, holds a
bachelor of science degree in mechanical engineering from Lehigh University. Mr.
Youngling  serves on the board of the  Empire  State  Electric  Energy  Research
Company and is a member of the Executive Committee of the New York Power Pool.

CAPITAL REQUIREMENTS, LIQUIDITY AND CAPITAL PROVIDED

Information as to "Capital Requirements," "Liquidity" and "Capital

                                       28

<PAGE>



Provided" appears in Item 7, "Management's  Discussion and Analysis of Financial
Condition and Results of Operations"  for the Year Ended December 31, 1996 under
the headings "Liquidity" and "Capital Requirements and Capital Provided."

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 were
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.  In June 1996, the New York State Court of Appeals rendered its opinion
on the  cross-appeals  filed by the parties  regarding the timing,  duration and
refundability  of PILOTs  under the LIPA Act. The Court  affirmed  portions of a
prior ruling by the Appellate  Division,  Second  Department by holding that (a)
LIPA's PILOT  obligation is perpetual,  (b) PILOTs,  like taxes,  are subject to
refund if the  assessment  upon which the PILOTs were based is  determined to be
excessive,  and (c) PILOTs phase down by ten percent of the prior year's amount,
rather than ten percent of the first PILOT year  amount,  until  PILOTs  reach a
level  that  equals  the taxes  that  would  have been  levied on the plant in a
non-operative state.  Additionally,  the Court modified the Appellate Division's
ruling by finding that PILOTs commence,  not at the time the Company transferred
Shoreham to LIPA in February 1992, but rather on December 1, 1992, the beginning
of the next tax year.

Unless  otherwise agreed by the parties,  the proper  assessment of Shoreham for
purposes of  determining  the proper  amount of PILOTs is to be  determined in a
proceeding challenging the Shoreham assessment for the 1992-93 tax year. If that
determination  results in PILOTs  that are less than the  amount of PILOTs  that
have already been paid,  LIPA, and therefore the Company,  should be entitled to
refunds of excessive PILOTs already made.

The costs of Shoreham included real property taxes imposed by, among others, the
Town of Brookhaven, and were capitalized by the Company during construction. The
Company 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

                                       29

<PAGE>



which those taxes were based for the years 1976  through  1992  (excluding  1979
which had been settled).  The Supreme Court  consolidated  the review of the tax
years at issue into two phases:  1976  through  1983 (Phase I); and 1984 through
1992  (Phase II).  In January  1996,  the  Company  received  approximately  $81
million,  including  interest,  from  Suffolk  County  pursuant to ruling by the
Supreme Court,  upheld on appeal,  that found that Shoreham had been  overvalued
for real property tax purposes in Phase I.

In  November  1996,  the  Supreme  Court  ruled  that  Shoreham  had  also  been
over-assessed  for real  property  tax  purposes  for  Phase  II.  According  to
preliminary  estimates by Company  officials based on this  overassessment,  the
Company is entitled to a tax refund of approximately $500 million plus interest.
If the  assessment  for the  1991-92  tax year is used to  determine  the proper
amount of PILOTs  this ruling  should  also result in a refund of  approximately
$260 million plus interest for PILOTs for the years 1992-1996.

The refund of any real property  taxes,  PILOTs,  and interest  thereon,  net of
litigation costs, will be used to reduce electric rates in the future.  However,
the court's ruling is subject to appeal and, as a result,  the Company is unable
to determine the amount and timing of any real property tax and PILOT refunds.

ENVIRONMENTAL

In February  1994, a lawsuit was filed in the United States  District  Court for
the Eastern  District of New York by the Town of Oyster Bay (Town),  against the
Company and nine 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  position,  cash flows or results of
operations.

In March 1996, the Village of Asharoken  filed a lawsuit  against the Company in
the New York Supreme Court, Suffolk County  (INCORPORATED  VILLAGE OF ASHAROKEN,
NEW YORK,  ET AL. V. LONG  ISLAND  LIGHTING  COMPANY).  The  Village  is seeking
monetary damages and injunctive relief based upon theories of negligence,  gross
negligence and nuisance in connection with the Company's design and construction
of the

                                       30

<PAGE>



Northport  Power Plant  which the  Village  alleges  upset the  littoral  drift,
thereby causing beach erosion. In November 1996, the Court decided the Company's
motion to dismiss the lawsuit, dismissing two of the three causes of action. The
Court limited  monetary  damages on the surviving  continuous  nuisance claim to
three years prior to the commencement of the action. The Company's liability, if
any,  resulting  from this  proceeding  cannot yet be determined.  However,  the
Company  does not  believe  that this  proceeding  will have a material  adverse
effect on its financial position, cash flows or results of operations.

In June  1996,  a lawsuit  was  commenced  against  the  Company in the New York
Supreme Court, Suffolk County (TOWN OF RIVERHEAD, ET AL. V. LONG ISLAND LIGHTING
COMPANY),  in which the plaintiffs seek monetary  damages and injunctive  relief
based upon  theories of nuisance,  breach of contract,  and breach of the Public
Trust in connection  with the  Company's  construction  of the Shoreham  Nuclear
Power Station and the Company's  diversion and  maintenance  of the Wading River
Creek.  The  plaintiffs  allege that the diversion of the Wading River Creek and
the  construction  of the Shoreham  Nuclear Power  Station have caused  negative
environmental  impacts on surrounding areas. The plaintiffs also allege that the
Company has contractual  obligations to perform annual  maintenance  dredging of
the Wading River Creek and beach  replenishment of certain beach front property.
In  September  1996,  the  Company  filed a motion to dismiss the  complaint  on
numerous  grounds.  In January 1997,  the  plaintiffs  cross-moved  for an order
seeking partial summary judgment. The Court has yet to act on these motions. The
Company's  liability,  if any,  resulting  from this  proceeding  cannot  yet be
determined. However, the Company does not believe that this proceeding will have
a material  adverse effect on its financial  position,  cash flows or results of
operations.

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 several individuals  alleging,  in separate actions, that the Company
discriminated  against  them,  or that they were the subject of  harassment,  on
various grounds.

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 for the past several years.

The Company has  estimated  that any costs to the Company  resulting  from these
matters will not have a material adverse effect on its financial position,  cash
flows or results of operations.

In May 1995, eight  participants of the Company's  Retirement  Income Plan (RIP)
filed a lawsuit against the Company, the RIP and Robert X.

                                       31

<PAGE>



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.  Discovery in this proceeding is ongoing. This proceeding arose in
connection  with the  plaintiffs'  withdrawal,  approximately  25 years ago,  of
contributions made to the RIP, 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
defend against said claims.

OTHER MATTERS

In January 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  anti-competitive  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  Company's
financial position, cash flows or results of operations.

A discussion  of legal  proceedings  related to  competitive  issues  facing the
Company appears in Item 7, in "Management's Discussion and Analysis of Financial
Condition  and Results of  Operations,"  for the Year Ended  December  31, 1996,
under the heading "Competitive Environment."


                                       32

<PAGE>



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

None


                                       33

<PAGE>




                                     PART II


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

At December 31,  1996,  the Company had 86,607  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.


<TABLE>
<CAPTION>

================================================================================
                             1996                           1995
--------------------------------------------------------------------------------
                     Market         Dividends       Market        Dividends
                     Prices         Declared        Prices        Declared
                                    Per Share                     Per Share
                -----------------              ----------------
                  High      Low                  High     Low
--------------------------------------------------------------------------------
<C>              <C>      <C>         <C>       <C>      <C>        <C>   
1st Quarter      $18 1/8  $15 7/8     $0.445    $16 3/4  $13 1/4    $0.445
2nd Quarter       17 7/8   16 1/8      0.445     17 1/8   14 3/8     0.445
3rd Quarter       17 3/4   16 5/8      0.445     17 3/4   15 3/8     0.445
4th Quarter       22 3/8   17 1/8      0.445     17 3/4   15 5/8     0.445
================================================================================
</TABLE>



                                       34

<PAGE>

Item 6: Selected Financial Data
<TABLE>
<CAPTION>

                                                         (In thousands of dollars except per share amounts)
------------------------------------------------------------------------------------------------------------
                                                  1996          1995         1994         1993         1992
------------------------------------------------------------------------------------------------------------
Summary of Operations                                                                               Table 1
------------------------------------------------------------------------------------------------------------
<S>                                         <C>           <C>          <C>          <C>          <C>
Revenues                                    $3,150,695    $3,075,128   $3,067,307   $2,880,995   $2,621,839
Operating expenses                           2,414,114     2,343,510    2,322,362    2,125,444    1,880,734
------------------------------------------------------------------------------------------------------------
Operating income                               736,581       731,618      744,945      755,551      741,105
Other income and (deductions)                   27,512        43,703       52,719       70,874       66,330
------------------------------------------------------------------------------------------------------------
Income before interest charges                 764,093       775,321      797,664      826,425      807,435
Interest charges                               447,629       472,035      495,812      529,862      505,461
------------------------------------------------------------------------------------------------------------
Net income                                     316,464       303,286      301,852      296,563      301,974
Preferred stock dividend requirements           52,216        52,620       53,020       56,108       63,954
------------------------------------------------------------------------------------------------------------
Earnings for Common Stock                   $  264,248    $  250,666   $  248,832    $ 240,455   $  238,020
============================================================================================================
Average common shares outstanding (000)        120,361       119,195      115,880      112,057      111,439
Earnings per Common Share                   $     2.20    $     2.10   $     2.15   $     2.15   $     2.14
============================================================================================================

Common stock dividends declared per share   $     1.78    $     1.78   $     1.78   $     1.76   $     1.72
Common stock dividends paid per share       $     1.78    $     1.78   $     1.78   $     1.75   $     1.71
Book value per common share at December 31  $    20.89    $    20.50   $    20.21   $    19.88   $    19.58
Common shares outstanding
   at December 31 (000)                        120,781       119,655      118,417      112,332      111,600
Common shareowners of record at December 31     86,607        93,088       96,491       94,877       86,111
============================================================================================================

------------------------------------------------------------------------------------------------------------
Capitalization Ratios*                                                                              Table 2
------------------------------------------------------------------------------------------------------------
Long-term debt                                    59.3%         61.8 %       62.5 %       65.0 %       64.7 %
Preferred stock                                    8.9           8.6          8.6          8.5          8.8
Common equity                                     31.8          29.6         28.9         26.5         26.5
------------------------------------------------------------------------------------------------------------
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               $  440,587    $  440,721   $  435,830   $  418,766   $  420,297
Less - Charged to construction and other       146,162       165,733      155,766      130,432      131,447
------------------------------------------------------------------------------------------------------------
Payroll and employee benefits charged to
   operations                                  294,425       274,988      280,064      288,334      288,850
------------------------------------------------------------------------------------------------------------
Fuel and Purchased Power
Fuel - electric operations                     313,607       266,039      261,154      287,349      282,138
Fuel - gas operations                          319,773       246,837      267,629      253,511      206,344
Purchased power costs                          331,736       309,807      307,584      292,136      280,914
Fuel cost adjustments deferred                  (1,865)       12,296       11,619       (5,405)     (27,612)
------------------------------------------------------------------------------------------------------------
Total fuel and purchased power                 963,251       834,979      847,986      827,591      741,784
------------------------------------------------------------------------------------------------------------
All other                                      204,786       236,405      260,590      233,326      209,095
------------------------------------------------------------------------------------------------------------
Total Operations and Maintenance Expense    $1,462,462    $1,346,372   $1,388,640   $1,349,251   $1,239,729
============================================================================================================

Full-time Employees at December 31               5,413         5,688        5,947        6,215        6,438
------------------------------------------------------------------------------------------------------------
</TABLE>
                                       35

<PAGE>

<TABLE>
<CAPTION>
                                                                                  (In thousands of dollars)
-------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------
                                                    1996         1995         1994         1993         1992
-------------------------------------------------------------------------------------------------------------
Electric Operating Income                                                                            Table 4
-------------------------------------------------------------------------------------------------------------
Revenues
-------------------------------------------------------------------------------------------------------------

<S>                                          <C>          <C>          <C>          <C>          <C>        
Residential                                  $ 1,205,133  $ 1,204,987  $ 1,202,124  $ 1,145,891  $ 1,045,799
Commercial and industrial                      1,174,499    1,194,014    1,196,422    1,132,487    1,076,302
Other system revenues                             50,513       52,472       52,477       49,790       49,395
-------------------------------------------------------------------------------------------------------------
Total system revenues                          2,430,145    2,451,473    2,451,023    2,328,168    2,171,496
Sales to other utilities                          20,927       19,104       14,895       12,872        9,997
Other revenues                                    15,363       13,437       15,719       11,069       13,139
-------------------------------------------------------------------------------------------------------------
Total Revenues                                 2,466,435    2,484,014    2,481,637    2,352,109    2,194,632
-------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations - fuel and purchased power            640,610      570,697      568,738      579,032      559,583
Operations - other                               288,315      293,184      310,438      306,116      294,909
Maintenance                                       98,007      106,031      107,573      111,765      105,341
Depreciation and amortization                    128,534      121,980      111,996      106,149      104,034
Base financial component amortization            100,971      100,971      100,971      100,971      100,971
Rate moderation component amortization           (24,232)      21,933      197,656       88,667      (30,444)
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                    109,532      155,532       (4,883)     (17,082)     (21,984)
Operating taxes                                  390,861      375,164      336,263      326,407      331,122
Federal income tax - current                      42,197       14,596       10,784        6,324          530
Federal income tax - deferred and other          138,307      168,377      156,646      158,941      158,908
-------------------------------------------------------------------------------------------------------------
Total Operating Expenses                       1,824,529    1,839,892    1,807,609    1,678,717    1,514,397
-------------------------------------------------------------------------------------------------------------
Electric Operating Income                    $   641,906  $   644,122  $   674,028  $   673,392  $   680,235
=============================================================================================================


                                                                                    (In thousands of dollars)
-------------------------------------------------------------------------------------------------------------
Gas Operating Income                                                                                 Table 5
-------------------------------------------------------------------------------------------------------------

Revenues
-------------------------------------------------------------------------------------------------------------
Residential - space heating                  $   367,721  $   323,729  $   326,474  $   310,109  $   243,950
            - other                               47,028       42,046       42,263       39,515       33,035
Commercial and industrial - space heating        144,807      130,964      126,092      106,140       90,363
                          - other                 36,549       34,293       35,275       33,181       29,094
-------------------------------------------------------------------------------------------------------------
Total firm revenues                              596,105      531,032      530,104      488,945      396,442
Interruptible revenues                            37,927       32,837       26,804       24,028       19,658
-------------------------------------------------------------------------------------------------------------
Total system revenues                            634,032      563,869      556,908      512,973      416,100
Off-system revenues, net                          26,254       16,213       20,904        5,812            -
Other revenues                                    23,974       11,032        7,858       10,101       11,107
-------------------------------------------------------------------------------------------------------------
Total Revenues                                   684,260      591,114      585,670      528,886      427,207
-------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations - fuel                                322,641      264,282      279,248      248,559      182,201
Operations - other                                92,761       90,054       95,576       81,692       77,300
Maintenance                                       20,128       22,124       27,067       22,087       20,395
Depreciation and amortization                     25,391       23,377       18,668       16,322       15,103
Other regulatory amortization                     17,756        6,073        9,211         (962)         (88)
Operating taxes                                   81,215       72,343       70,632       59,440       57,866
Federal income tax - deferred and other           29,693       25,365       14,351       19,589       13,560
-------------------------------------------------------------------------------------------------------------
Total Operating Expenses                         589,585      503,618      514,753      446,727      366,337
-------------------------------------------------------------------------------------------------------------
Gas Operating Income                         $    94,675  $    87,496  $    70,917  $    82,159  $    60,870
=============================================================================================================
</TABLE>

                                       36
<PAGE>

<TABLE>
<CAPTION>

-------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------
                                                    1996         1995         1994         1993         1992
-------------------------------------------------------------------------------------------------------------
Electric Sales and Customers                                                                         Table 6
-------------------------------------------------------------------------------------------------------------
<S>                                            <C>          <C>          <C>          <C>          <C>
Sales - millions of kWh
Residential                                        7,203        7,156        7,159        7,118        6,788
Commercial and industrial                          8,242        8,336        8,394        8,257        8,181
Other system sales                                   441          460          457          449          471
-------------------------------------------------------------------------------------------------------------
Total system sales                                15,886       15,952       16,010       15,824       15,440
Sales to other utilities                             528          620          372          304          227
-------------------------------------------------------------------------------------------------------------
Total Sales                                       16,414       16,572       16,382       16,128       15,667
=============================================================================================================
Customers - monthly average
Residential                                      920,930      915,162      908,490      905,997      902,885
Commercial and industrial                        104,488      103,669      102,490      102,254      101,838
Other                                              4,595        4,549        4,583        4,553        4,593
-------------------------------------------------------------------------------------------------------------
Total Customers - monthly average              1,030,013    1,023,380    1,015,563    1,012,804    1,009,316
=============================================================================================================
Customers at December 31                       1,031,205    1,025,107    1,016,739    1,011,965    1,009,028
-------------------------------------------------------------------------------------------------------------
Residential
kWh per customer                                   7,821        7,819        7,880        7,857        7,518
Revenue per kWh                                    16.73c.      16.84c.      16.79c.      16.10c.      15.41c.
-------------------------------------------------------------------------------------------------------------
Commercial and Industrial
kWh per customer                                  78,880       80,410       81,901       80,750       80,333
Revenue per kWh                                    14.25c.      14.32c.      14.25c.      13.72c.      13.16c.
-------------------------------------------------------------------------------------------------------------
System
kWh per customer                                  15,423       15,588       15,765       15,624       15,297
Revenue per kWh                                    15.30c.      15.37c.      15.31c.      14.71c.      14.06c.
=============================================================================================================



-------------------------------------------------------------------------------------------------------------
Gas Sales and Customers                                                                               Table 7
-------------------------------------------------------------------------------------------------------------
Sales - thousands of Dth
Residential - space heating                       37,697       35,336       35,693       37,191       35,089
            - other                                3,153        2,929        3,151        3,297        3,203
Commercial and industrial - space heating         16,763       16,170       15,679       14,366       13,662
                          - other                  4,291        4,269        4,366        4,329        4,338
-------------------------------------------------------------------------------------------------------------
Total firm sales                                  61,904       58,704       58,889       59,183       56,292
Interruptible sales                                7,869        9,176        6,914        5,920        5,090
Off-system sales                                   7,457        7,743        7,232        2,894            -
-------------------------------------------------------------------------------------------------------------
Total Sales                                       77,230       75,623       73,035       67,997       61,382
=============================================================================================================
Customers - monthly average
Residential  - space heating                     249,758      245,452      239,857      233,882      227,834
             - other                             161,164      162,114      163,608      166,974      169,189
Commercial and industrial - space heating         35,803       35,027       33,776       32,783       31,666
                          - other                 10,084       10,313       10,448       10,631       10,777
-------------------------------------------------------------------------------------------------------------
Total firm customers                             456,809      452,906      447,689      444,270      439,466
Interruptible customers                              651          623          576          542          531
-------------------------------------------------------------------------------------------------------------
Total Customers  - monthly average               457,460      453,529      448,265      444,812      439,997
=============================================================================================================
Customers at December 31                         460,028      455,869      449,906      446,384      442,117
-------------------------------------------------------------------------------------------------------------
Residential
Dth per customer                                    99.4         93.9         96.3        101.0         96.4
Revenue per Dth                                   $10.15      $  9.56      $  9.49       $ 8.64       $ 7.23
-------------------------------------------------------------------------------------------------------------
Commercial and Industrial
Dth per customer                                   458.8        450.8        453.3        430.6        424.1
Revenue per Dth                                  $  8.61      $  8.09      $  8.05       $ 7.45       $ 6.64
-------------------------------------------------------------------------------------------------------------
System
Dth per customer                                   152.5        149.7        146.8        146.4        139.5
Revenue per Dth                                  $  9.09      $  8.31      $  8.46       $ 7.88       $ 6.78
-------------------------------------------------------------------------------------------------------------
</TABLE>

                                       37
<PAGE>

<TABLE>
<CAPTION>

                                                  1996          1995         1994         1993         1992
------------------------------------------------------------------------------------------------------------
Electric Operations                                                                                 Table 8
------------------------------------------------------------------------------------------------------------
Energy - millions of kWh
<S>                                            <C>           <C>          <C>          <C>          <C>
Net generation                                  10,319        10,744       10,034       10,514       10,592
Power purchased                                  7,388         7,143        7,640        7,023        6,438
------------------------------------------------------------------------------------------------------------
Total Energy Available                          17,707        17,887       17,674       17,537       17,030
============================================================================================================

System sales                                    15,886        15,952       16,010       15,824       15,440
Company use and unaccounted for                  1,293         1,315        1,292        1,409        1,363
------------------------------------------------------------------------------------------------------------
Total system energy requirements                17,179        17,267       17,302       17,233       16,803
Sales to other utilities                           528           620          372          304          227
------------------------------------------------------------------------------------------------------------
Total Energy Available                          17,707        17,887       17,674       17,537       17,030
============================================================================================================

Peak Demand - MW
Station coincident demand                        2,848         3,591        3,253        2,931        2,975
Power purchased - net                              757           486          629        1,036          636
------------------------------------------------------------------------------------------------------------
System Peak Demand                               3,605         4,077        3,882        3,967        3,611
============================================================================================================
System Capability  - MW
Company stations                                 3,978         3,957        4,063        4,063        4,091
Nine Mile Point 2 (18% share)                      205           203          189          188          188
Firm purchases - net                               710           713          616          548          432
------------------------------------------------------------------------------------------------------------
Total Capability                                 4,893         4,873        4,868        4,799        4,711
============================================================================================================
Fuel Consumed for Electric Operations
Oil - thousands of barrels                       7,063         5,154        7,518        9,740       10,656
Gas - thousands of dth                          50,173        69,826       44,308       36,269       34,475
Nuclear - thousands of MW days - thermal           200           169          203          175          124
------------------------------------------------------------------------------------------------------------

Fuel Mix (Percentage of total energy available)
Oil                                                 24 %          17 %         25 %         34 %         37%
Gas                                                 25            36           23           19           19
Purchased power                                     42            40           43           40           38
Nuclear fuel                                         9             7            9            7            6
------------------------------------------------------------------------------------------------------------
Total                                              100 %         100 %        100 %        100 %        100%
============================================================================================================


------------------------------------------------------------------------------------------------------------
Gas Operations                                                                                      Table 9
------------------------------------------------------------------------------------------------------------
Company Requirements-thousands of Dth
System sales                                    69,773        67,880       65,803       65,103       61,382
Off-system sales                                 7,457         7,743        7,232        2,894            -
Company use and unaccounted for                  3,738         2,054        2,516        1,905        3,577
------------------------------------------------------------------------------------------------------------
Total Company Requirements                      80,968        77,677       75,551       69,902       64,959
============================================================================================================
Maximum Day Sendout - Dth                      524,762       564,874      585,227      485,896      448,726
------------------------------------------------------------------------------------------------------------
System Capability - Dth per day
Natural gas                                    648,695       592,335      579,897      561,584      561,584
LNG manufactured or LP gas                     123,300       124,700      125,700      120,700      120,700
------------------------------------------------------------------------------------------------------------
Total Capability                               771,995       717,035      705,597      682,284      682,284
============================================================================================================
Heating Degree Days
(30 year average 4,942)                          5,132         4,906        4,839        4,899        5,066
------------------------------------------------------------------------------------------------------------
</TABLE>
                                       38

<PAGE>

<TABLE>
<CAPTION>
                                                                                    (In thousands of dollars)      
-------------------------------------------------------------------------------------------------------------
                                                    1996         1995         1994         1993         1992
-------------------------------------------------------------------------------------------------------------
Balance Sheet                                                                                       Table 10
-------------------------------------------------------------------------------------------------------------
Assets
<S>                                          <C>          <C>          <C>          <C>          <C>
Net utility plant                            $ 3,695,170  $ 3,594,998  $ 3,498,346  $ 3,347,557  $ 3,161,148
Regulatory Assets
  Base financial component                     3,281,548    3,382,519    3,483,490    3,584,461    3,685,432
  Rate moderation component                      402,213      383,086      463,229      609,827      651,657
  Shoreham post-settlement costs                 991,795      968,999      922,580      777,103      586,045
  Shoreham nuclear fuel                           69,113       71,244       73,371       75,497       77,629
  Unamortized cost of issuing securities         194,151      222,567      254,482      174,694      195,524
  Postretirement benefits other than pensions    360,842      383,642      412,727      402,921            -
  Regulatory tax asset                         1,772,778    1,802,383    1,831,689    1,848,998            -
  Other                                          199,879      229,809      250,804      247,858      190,008
-------------------------------------------------------------------------------------------------------------
Total Regulatory Assets                        7,272,319    7,444,249    7,692,372    7,721,359    5,386,295
-------------------------------------------------------------------------------------------------------------
Nonutility property and other investments         18,597       16,030       24,043       23,029       20,730
Current assets                                 1,146,602    1,411,938    1,090,230    1,088,831      979,131
Deferred charges                                  76,991       60,382      174,298      272,995      305,819
-------------------------------------------------------------------------------------------------------------
Total Assets                                 $12,209,679  $12,527,597  $12,479,289  $12,453,771  $ 9,853,123
=============================================================================================================

Capitalization and Liabilities
Long-term debt                               $ 4,471,675  $ 4,722,675  $ 5,162,675  $ 4,887,733  $ 4,755,733
Unamortized discount on debt                     (14,903)     (16,075)     (17,278)     (17,393)     (14,731)
-------------------------------------------------------------------------------------------------------------
                                               4,456,772    4,706,600    5,145,397    4,870,340    4,741,002
-------------------------------------------------------------------------------------------------------------
Preferred stock - redemption required            638,500      639,550      644,350      649,150      557,900
Preferred stock - no redemption required          63,664       63,934       63,957       64,038      154,276
-------------------------------------------------------------------------------------------------------------
Total Preferred Stock                            702,164      703,484      708,307      713,188      712,176
-------------------------------------------------------------------------------------------------------------
Common stock                                     603,921      598,277      592,083      561,662      558,002
Premium on capital stock                       1,127,971    1,114,508    1,101,240    1,010,283      998,089
Capital stock expense                            (49,330)     (50,751)     (52,175)     (50,427)     (39,304)
Retained earnings                                840,867      790,919      752,480      711,432      667,988
Treasury stock, at cost                              (60)           -            -            -            -
-------------------------------------------------------------------------------------------------------------
Total Common Shareowners' Equity               2,523,369    2,452,953    2,393,628    2,232,950    2,184,775
-------------------------------------------------------------------------------------------------------------
Total Capitalization                           7,682,305    7,863,037    8,247,332    7,816,478    7,637,953
-------------------------------------------------------------------------------------------------------------
Regulatory Liabilities
  Regulatory liability component                 198,398      277,757      357,117      436,476      515,835
  1989 Settlement credits                        127,442      136,655      145,868      155,081      164,294
  Regulatory tax liability                       102,887      116,060      111,218      114,748            -
  Other                                          146,852      132,891      147,041      142,455      102,718
-------------------------------------------------------------------------------------------------------------
Total Regulatory Liabilities                     575,579      663,363      761,244      848,760      782,847
-------------------------------------------------------------------------------------------------------------
Current liabilities                              949,627    1,050,021      601,311    1,188,972    1,177,130
Deferred credits                               2,573,208    2,502,040    2,365,780    2,166,405      237,893
Operating reserves                               428,960      449,136      503,622      433,156       17,300
-------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities         $12,209,679  $12,527,597  $12,479,289  $12,453,771  $ 9,853,123
=============================================================================================================

                                                                                    (In thousands of dollars)
-------------------------------------------------------------------------------------------------------------
Construction Expenditures*                                                                          Table 11
-------------------------------------------------------------------------------------------------------------
Electric                                     $   143,435  $   145,472  $   136,041  $   137,583  $   141,752
Gas                                               71,690       79,536      120,019      124,859      104,028
Common                                            27,659       21,477       23,610       42,251       27,124
-------------------------------------------------------------------------------------------------------------
Total Construction Expenditures              $   242,784  $   246,485  $   279,670  $   304,693  $   272,904
=============================================================================================================
</TABLE>

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

                                       39
<PAGE>

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

RESULTS OF OPERATIONS

EARNINGS

Earnings for the years 1996, 1995 and 1994 were as follows:

<TABLE>
<CAPTION>

            (In millions of dollars and shares except earnings per share)
--------------------------------------------------------------------------------
                                         1996         1995           1994
--------------------------------------------------------------------------------
<S>                                 <C>           <C>            <C>     
Net income                          $   316.5     $  303.3       $  301.8
Preferred stock dividend
  requirements                           52.2         52.6           53.0
--------------------------------------------------------------------------------
Earnings for Common Stock           $   264.3     $  250.7       $  248.8
================================================================================
Average common shares
  outstanding                           120.4        119.2          115.9
--------------------------------------------------------------------------------
Earnings per Common Share           $    2.20     $   2.10       $   2.15
================================================================================
</TABLE>


The Company's  1996 earnings are higher for both the electric and gas businesses
as compared to 1995. While the Company's  allowed rate of return in 1996 was the
same as 1995, the higher earnings for the electric  business are a result of the
Company's  increased  investment in electric plant in 1996, as compared to 1995.
Factors  contributing to the increase in electric  business earnings include the
Company's  continued efforts to reduce  operations and maintenance  expenses and
the efficient use of cash generated by operations to retire maturing debt.

The  increase  in  earnings  in the gas  business  was the result of  additional
revenues  due  to the  continued  growth  in the  number  of gas  space  heating
customers. Also contributing to the increase in gas business earnings was a 3.2%
rate  increase  which  became  effective  December  1, 1995,  and an increase in
off-system sales.

The  Company's  1995 earnings per common share were lower than 1994 earnings per
common share as a result of the New York State Public Service Commission's (PSC)
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.  Partially  offsetting  the effects on earnings of the electric rate
order was higher gas business earnings in 1995 when compared to 1994.

REVENUES

ELECTRIC REVENUES

Revenues from the Company's electric  operations totaled $2.5 billion in each of
the years ended December 31, 1996, 1995 and 1994.

                                       40

<PAGE>




The Company  experienced a growth in electric  system sales in 1996 on a weather
normalized  basis compared to 1995 and in 1995 compared to 1994.  This growth is
primarily attributable to the addition of new electric customers.  The Company's
electric revenues fluctuate as a result of system growth, variations in weather,
and fuel costs,  as electric base rates have remained  unchanged  since December
1993.  However,  these  variations have no impact on earnings due to the current
electric rate structure which includes a revenue reconciliation  mechanism which
eliminates  the impact on  earnings  caused by sales  volumes  that are above or
below  adjudicated  levels.  Total  electric  sales volumes were 16,414  million
kilowatt hour (kWh) in 1996,  compared to 16,572  million kWh in 1995 and 16,382
million kWh in 1994.

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

GAS REVENUES

Revenues  from the Company's gas  operations  for the years 1996,  1995 and 1994
were $684 million, $591 million and $586 million, respectively.

The increase in 1996 gas revenues  when  compared to 1995 is  attributable  to a
3.2% gas rate increase  which became  effective on December 1, 1995, an increase
in sales  volumes,  an  increase in gas fuel  expense  recoveries  and  revenues
generated through the Company's  continuing  efforts to provide  non-traditional
services,  including  off-system  sales.  The  increase  in 1995  revenues  when
compared to 1994 is attributable to a 3.8% gas rate increase, effective December
1, 1994, offset by a decrease in fuel expense recoveries.

The Company  experienced  a 6.3% increase in firm sales volumes in 1996 compared
to 1995, due to the addition of approximately  5,100 gas space heating customers
and colder  weather  during the 1996 heating  season when  compared to the prior
year.  The  increase  in sales  volumes  caused by  variations  in weather has a
limited impact on revenues as the Company's current gas rate structure  includes
a weather  normalization  clause  which  mitigates  the  impact on  revenues  of
experiencing weather that is warmer or colder than normal.

The Company continues to increase its space heating  penetration through various
marketing  programs,  and as a result of these  efforts has added  approximately
20,000 gas space heating customers over the past three years.

The  recovery  of gas fuel  expenses  in 1996 when  compared  to 1995  increased
approximately $31 million as a result of higher average gas prices and increased
per customer usage due to colder weather than  experienced in the prior year. In
1995, the Company experienced a decrease of $24 million in the recoveries of gas
fuel expenses  when compared to the same period of 1994,  primarily due to lower
average gas prices.


                                       41

<PAGE>





In 1996, non-traditional revenues totaled $46 million, including $37 million for
off-system  sales. In 1995 and 1994,  revenues from off-system sales totaled $24
million and $26 million,  respectively.  Profits generated from off-system sales
are  allocated  85% to the firm gas  ratepayer  and 15% to the  shareowners,  in
accordance with PSC mandates.

OPERATING EXPENSES

FUEL AND PURCHASED POWER

Fuel and  purchased  power  expenses  for the years 1996,  1995 and 1994 were as
follows:
<TABLE>
<CAPTION>

                                                   (In millions of dollars)
--------------------------------------------------------------------------------
                                               1996          1995        1994
--------------------------------------------------------------------------------
<S>                                           <C>           <C>         <C>
Fuel for Electric Operations
  Oil                                         $ 158         $  98       $ 145
  Gas                                           138           149         101
  Nuclear                                        15            14          15
  Purchased Power                               329           310         308
--------------------------------------------------------------------------------
Total                                           640           571         569
--------------------------------------------------------------------------------
Gas Fuel                                        323           264         279
--------------------------------------------------------------------------------
Total                                         $ 963         $ 835       $ 848
================================================================================
</TABLE>


Electric fuel and purchased  power mix for the years 1996, 1995 and 1994 were as
follows:
<TABLE>
<CAPTION>

                                                           (In thousands of MWH)
--------------------------------------------------------------------------------
                             1996                  1995                1994
--------------------------------------------------------------------------------
                            MWH         %      MWH         %      MWH         %
<S>                       <C>         <C>    <C>         <C>    <C>          <C>
Oil                        4,219       24%    3,099       17%    4,480       25%
Gas                        4,542       25     6,344       36     4,056       23
Nuclear                    1,558        9     1,301        7     1,498        9
Purchased Power            7,388       42     7,143       40     7,640       43
--------------------------------------------------------------------------------
Total                     17,707      100%   17,887      100%   17,674      100% 
================================================================================
</TABLE>

During 1996, the Company  completed the first of two planned  conversions of oil
fired steam  generating units at its Port Jefferson Power Station to dual firing
units,  bringing the total number of steam units capable of burning  natural gas
to eight.  Of the  Company's  eight steam  generation  units  capable of burning
natural gas, six are dual-fired,  providing the Company with the ability to burn
the most cost efficient fuel available,  consistent with seasonal  environmental
requirements,  thereby providing customers with the lowest possible cost energy.
The conversion of the second unit at Port  Jefferson has a projected  completion
date of May 1997.

As a result of a sharp  increase  in the cost of  natural  gas  during the year,
generation with oil became more economical than generation with gas. The

                                       42

<PAGE>



total  barrels of oil  consumed for electric  operations  were 7.1 million,  5.2
million, and 7.5 million for the years 1996, 1995 and 1994, respectively.

Cogenerators,  Independent  Power  Producers  (IPPs) and energy  supplied from a
facility in Holtsville,  New York, owned by the New York Power Authority (NYPA),
and constructed for the benefit of the Company,  provided  approximately  16% of
the total  energy made  available  by the Company in 1996 and 1995,  compared to
approximately 14% in 1994. Increases in purchase power expenses in 1996 compared
to 1995 is due to  increases  in the  average  unit  price  and in the  quantity
purchased.  The increase in purchased power expenses in 1995 compared to 1994 is
primarily  attributable to increased purchases from the NYPA Holtsville facility
which began commercial operations in 1994.

Gas system fuel  expense  increased in 1996 by $58 million  when  compared  with
1995, due to higher firm sales volumes,  a 26% increase in the Company's average
price of gas and higher off-system gas sales. In 1995, this expense decreased by
$15 million  when  compared  with 1994,  as a result of a decline in the average
price of gas, despite higher sales volumes.

Variations  in fuel costs have no impact on operating  results as the  Company's
current rate  structures  include fuel  adjustment  clauses  whereby  variations
between actual fuel costs and fuel costs included in base rates are deferred and
subsequently returned to or collected from customers.  However, in a period when
base  electric  fuel costs are in excess of actual  electric  fuel  costs,  such
amounts are credited to the RMC.

OPERATIONS AND MAINTENANCE EXPENSES

Operations and maintenance  (O&M) expenses,  excluding fuel and purchased power,
were $499 million,  $511 million and $541 million,  for the years 1996, 1995 and
1994,  respectively.  The  decrease  in O&M for 1996  compared  to 1995 and 1995
compared to 1994 was primarily due to the Company's  continuing cost containment
program which resulted in lower plant maintenance  expenses,  lower distribution
expenses and lower administrative and general expenses.

RATE MODERATION COMPONENT

The Rate  Moderation  Component  (RMC)  represents  the  difference  between the
Company's revenue  requirements under  conventional  ratemaking and the revenues
provided by its electric  rate  structure.  The RMC is adjusted  monthly for the
operation of the Company's Fuel  Moderation  Component  (FMC)  mechanism and the
difference  between the Company's  share of actual  operating costs at Nine Mile
Point Nuclear Power Station,  Unit 2 (NMP2) and amounts provided for in electric
rates.

In 1996, the Company recorded a non-cash credit to income of  approximately  $50
million, representing the amount by which revenue requirements exceeded revenues
provided for under the current  electric rate  structure.  Partially  offsetting
this accretion were the effects of the FMC mechanism and the differences between
actual and adjudicated operating costs for NMP2, as

                                       43

<PAGE>



discussed  above.  The  adjustments  to the  accretion  of the RMC  totaled  $26
million,  of  which  $24  million  was  derived  from the  operation  of the FMC
mechanism.

In  1995  and  1994,  the  Company  recorded   non-cash  charges  to  income  of
approximately $22 million and $198 million, respectively, after giving effect to
the credits  generated  principally by the operation of the FMC  mechanism.  FMC
credits for 1995 and 1994 totaled $87 million and $83 million, respectively.

For a  further  discussion  of  the  RMC,  see  Note  3 of  Notes  to  Financial
Statements.

OTHER REGULATORY AMORTIZATION

In 1996, the net total of other regulatory amortization was a non-cash charge to
income of $127 million, compared to $162 million in 1995 and $4 million in 1994.

The change from 1996 to 1995 is primarily  attributable  to the operation of the
revenue  reconciliation  mechanism  included  in  the  Company's  electric  rate
structure,  partially  offset by a non-cash  charge to income recorded to reduce
the Company's earnings to the levels provided for in rates for both the electric
and gas businesses.

The electric revenue  reconciliation  mechanism,  as established under the LILCO
Ratemaking  and  Performance  Plan (LRPP),  eliminates the impact on earnings of
experiencing  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).  Variations in electric  revenue  resulting  from  differences
between actual and adjudicated net margin sales levels are deferred on a monthly
basis during the rate year. The Company  recorded a non-cash charge to income of
approximately  $3  million  and  $64  million  for  the  years  1996  and  1995,
respectively,  representing a net margin level in excess of that provided for in
rates.  The decrease  between 1996 and 1995 was the result of an increase in the
adjudicated  net margin  sales  levels and  cooler  summer  weather in 1996 when
compared to 1995.

Earnings in excess of the Company's allowed return on common equity generated by
the  electric  business  was  approximately  $9  million  for the 1996 rate year
compared to  approximately $6 million for the 1995 rate year. In accordance with
the Company's  electric rate  structure,  earnings  above the allowed  return on
common equity are applied against the RMC balance.  The  ratepayers'  portion of
gas  earnings in excess of a 10.6% return on common  equity  totaled $10 million
for the 1996 rate year compared to $1 million in 1995.

In 1995, other  regulatory  amortization was higher than 1994 as a result of the
operation  of  the  revenue  reconciliation  mechanism  and an  increase  in the
amortization of prior period LRPP  deferrals,  as more fully discussed in Note 3
of Notes to Financial Statements.


                                       44

<PAGE>



OPERATING TAXES

Operating  taxes were $472 million,  $448 million and $407 million for the years
1996,  1995 and 1994,  respectively.  The  increase in 1996  compared to 1995 is
primarily  attributable  to increased  property  taxes,  as well as higher gross
receipts taxes due to increased revenues.  The increase in 1995 when compared to
1994 is primarily attributable to higher property taxes.

FEDERAL INCOME TAX

Federal income tax was $209 million, $206 million and $177 million for the years
1996,  1995 and 1994,  respectively.  The increase in federal income tax in 1996
when compared to 1995 was primarily  attributable to higher earnings,  partially
offset by the  utilization of investment tax credits.  The increase in 1995 when
compared  to  1994  was  primarily  attributable  to  higher  earnings  and  the
amortization  of previously  deferred taxes resulting from a change in corporate
tax rates.

OTHER INCOME AND DEDUCTIONS, NET

Other  income and  deductions,  totaled $19  million  for 1996,  compared to $34
million and $35 million for 1995 and 1994,  respectively.  The  decrease in 1996
when  compared  to  1995  is  primarily   attributable  to  the  recognition  of
nonrecurring  expenditures  associated  with one of the  Company's  wholly-owned
subsidiaries,  a decrease in non-cash  carrying  charge income  associated  with
regulatory  assets not  currently  in rate base and the  recognition  in 1995 of
certain litigation  proceeds related to the construction of the Shoreham Nuclear
Power  Station.  The change from 1995 when  compared to 1994, in addition to the
effects  of the  litigation  proceeds,  resulted  from lower  non-cash  carrying
charges  and lower  incentive  income as a result of the PSC rate  order for the
rate year ended November 30, 1995,  which eliminated  certain  performance-based
incentives.

INTEREST EXPENSE

Lower interest expense in 1996 compared to 1995, and in 1995 compared to 1994 is
primarily  attributable to lower  outstanding  debt levels,  partially offset by
higher letter of credit and commitment  fees  associated  with the change in the
Company's  credit  rating in 1996.  For a further  discussion  of the  Company's
investment  ratings,  see the  discussion  below under the  heading  "Investment
Rating".  The Company's  strategy  continues to be the  application of available
cash balances  toward the  satisfaction  of maturing debt whenever  practicable.
Accordingly,  in  1996,  the  Company  used  cash on hand  and  cash  previously
deposited with the Trustee of the General & Refunding  (G&R) Mortgage to satisfy
the mandatory  redemption  of $415 million of the  Company's  G&R Bonds.  During
1995,  the  Company  used  approximately  $75 million of cash on hand to redeem,
prior to maturity, the remaining outstanding First Mortgage Bonds.

                                       45

<PAGE>



LIQUIDITY

During 1996,  cash generated from operations  exceeded the Company's  operating,
construction  and dividend  requirements.  This positive cash flow is the result
of, among other things: (i) the Company's  continuing efforts to reduce both O&M
expenses and construction  expenditures;  (ii) lower interest payments resulting
from lower debt levels; and (iii) increased revenues from off-system gas sales.

At December  31,  1996,  the  Company's  cash and cash  equivalents  amounted to
approximately  $280  million,  compared to $351 million at December 31, 1995. In
addition,  the Company  has  available  for its use a  revolving  line of credit
through October 1, 1997,  provided by its 1989 Revolving  Credit Agreement (1989
RCA). In July 1996, at the Company's request,  the amount committed by the banks
participating in the facility was reduced from $300 million to $250 million. The
Company  believes this action is  appropriate  given the levels of cash on hand,
projected  future cash generated  from  operations and modest debt and preferred
stock  maturities  through 1998.  This line of credit is secured by a first 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 RMC balance by
the amount received,  net of litigation  costs incurred by the Company.  The PSC
has not yet  acted  on the  Company's  petition  and,  therefore,  such  amounts
continue to be  deferred  on the  Company's  balance  sheet as other  regulatory
liabilities.

In November  1996, the New York State Supreme Court ruled that Shoreham had also
been  over-assessed  for real  property  tax purposes for the years 1984 through
1992. Based on this  over-assessment,  the Company has  preliminarily  estimated
that it is entitled to a tax refund of approximately $500 million plus interest.
If the  assessment  for the  1991-92  tax year is used to  determine  the proper
amount of payments-in-lieu-of-taxes  (PILOTs), this ruling should also result in
a refund of  approximately  $260 million plus  interest for PILOTs for the years
1992-1996.

The refund of any real property  taxes,  PILOTs,  and interest  thereon,  net of
litigation costs, will be used to reduce electric rates in the future.  However,
the court's ruling is subject to appeal and, as a result,  the Company is unable
to determine the amount and timing of any real property tax and PILOT refunds.

The Company does not intend to access the financial  markets during 1997 to meet
any of its  operating,  construction  or refunding  requirements,  including the
retirement of its $250 million of maturing  debt on February 15, 1997.  However,
if  necessary,  the Company will avail itself of interim  financing via the 1989
RCA to satisfy a portion of the debt maturing in

                                       46

<PAGE>



February 1997.  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 $101 million of maturing  debt in
1998 and the  repayment  of $454  million of  maturing  debt and $22  million of
mandatory  redemption  requirements  of  preferred  stock in 1999,  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 Company has  protested  some of the proposed  adjustments
which are presently under review by the Regional  Appeals Office of the Internal
Revenue  Service.  The  Company  believes  that  cash  balances  at the  time of
settlement  will be sufficient to satisfy any settlement  reached.  However,  if
necessary,  the Company will avail itself of interim  financing via the 1989 RCA
to meet this obligation. The Company currently believes that a settlement of the
1981  through 1989 years  should be reached  with the  Regional  Appeals  Office
sometime in 1997.

CAPITALIZATION

The Company's capitalization, including current maturities of long-term debt and
current  redemption  requirements  of preferred  stock, at December 31, 1996 and
1995, was $7.9 billion and $8.3 billion,  respectively. At December 31, 1996 and
1995, the Company's capitalization ratios were as follows:
<TABLE>
<CAPTION>
                                               1996               1995
-----------------------------------------------------------------------
   <S>                                        <C>                <C>  
   Long-term debt                              59.3%              61.8%
   Preferred stock                              8.9                8.6
   Common shareowners' equity                  31.8               29.6
-----------------------------------------------------------------------
                                              100.0%             100.0%
=======================================================================
</TABLE>

In support  of the  Company's  continuing  goal to reduce  its debt  ratio,  the
Company,  in 1996,  retired at maturity $415 million of G&R Bonds,  with cash on
hand and cash  previously  deposited  with the Trustee of the G&R Mortgage.  The
Company  expects  to use cash on hand to satisfy  the $250  million of G&R Bonds
scheduled to mature in February 1997.  However,  if necessary,  the Company will
avail itself of interim  financing via the 1989 RCA to satisfy a portion of this
obligation.

INVESTMENT RATING

The  Company's  securities  are rated by  Standard  and  Poor's  (S&P),  Moody's
Investors Service,  Inc.  (Moody's),  Fitch Investors Service,  L.P. (Fitch) and
Duff & Phelps Credit Rating Co. (D&P). The rating agencies have been

                                       47

<PAGE>



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 June 1996,  Moody's  downgraded  its rating of the  Company's  G&R Bonds from
minimum  investment grade to one notch below minimum  investment grade.  Moody's
also  downgraded its ratings of the Company's  debentures  and preferred  stock,
which were already below minimum investment grade.

In  November  1996,  Moody's  revised its  outlook on the  Company's  G&R Bonds,
debentures  and preferred  stock from  negative to stable,  as a result of a New
York State Supreme Court ruling that found that Shoreham had been overvalued for
real property taxes for the years 1984 through 1992. For a further discussion of
this ruling, see Item 3, Legal Proceedings.

As a result of the  announcement  of the merger  agreement  on December 29, 1996
between the Company and The  Brooklyn  Union Gas  Company,  the  Company's  bond
ratings  "outlook"/"Credit Watch" was raised to "positive" by Moody's, S & P and
Fitch.  D&P has  reaffirmed  the Company's  ratings but maintains a rating watch
with uncertain implications.

At December 31, 1996 the ratings for each of the Company's principal  securities
were as follows:
<TABLE>
<CAPTION>

                       S&P      MOODY'S      FITCH    D&P
--------------------------------------------------------------------------------
<S>                    <C>      <C>          <C>      <C>
G&R Bonds              BBB-     Ba1          BBB-     BBB
Debentures             BB+      Ba3          BB+      BB+
PREFERRED STOCK        BB+      ba3          BB-*     BB
--------------------------------------------------------------------------------
MINIMUM INVESTMENT
   GRADE               BBB-     Baa3         BBB-     BBB-
================================================================================
</TABLE>

Bold face indicates securities that meet or exceed minimum investment grade.

* In December 1996, Fitch announced that it will begin rating preferred stock on
the same scale as investment grade and speculative  bonds and, as a result,  the
Company's preferred stock is now rated BB-.


                                       48

<PAGE>



CAPITAL REQUIREMENTS AND CAPITAL PROVIDED

Capital requirements and capital provided for 1996 and 1995 were as follows:
<TABLE>
<CAPTION>
                                                (In millions of dollars)
------------------------------------------------------------------------
                                                      1996          1995
------------------------------------------------------------------------
<S>                                                  <C>           <C>
CAPITAL REQUIREMENTS
Construction*
   Electric                                          $ 142         $ 144
   Gas                                                  71            79
   Common                                               27            21
------------------------------------------------------------------------
Total Construction                                     240           244
------------------------------------------------------------------------
Refundings and Dividends
   Long-term debt                                      415           100
   Preferred stock                                       5             5
   Common stock dividends                              214           211
   Preferred stock dividends                            52            53
------------------------------------------------------------------------
Total Refundings and Dividends                         686           369
------------------------------------------------------------------------
Shoreham Post-settlement Costs                          52            71
------------------------------------------------------------------------
TOTAL CAPITAL REQUIREMENTS                           $ 978         $ 684
========================================================================
CAPITAL PROVIDED
Cash generated from operations                       $ 892         $ 772
Long-term debt issued                                    -            49
Common stock issued                                     19            20
Increase(decrease) in cash                              71          (166)
OTHER INVESTING ACTIVITIES                              (4)            9
------------------------------------------------------------------------
Total Capital Provided                               $ 978         $ 684
========================================================================
</TABLE>

* Excludes  non-cash  allowance  for other funds used during  construction.  For
further information, see the Statement of Cash Flows.

For 1997,  total capital  requirements  (excluding  common stock  dividends) are
estimated  to  be  $629  million,  of  which  maturing  debt  is  $251  million,
construction  requirements  are $282 million,  preferred stock dividends are $52
million,   preferred   stock   sinking   funds  are  $1  million  and   Shoreham
post-settlement  costs are $43 million  (including  $41  million  for  payments-
in-lieu-of-taxes).  The Company  believes that cash  generated  from  operations
coupled with  beginning  cash  balances  will be  sufficient to meet all capital
requirements in 1997.

Based upon the  projections  of peak  demand for  electric  power,  the  Company
believes it will need to acquire additional  generating or demand-side resources
starting  in 1998  in  order  to  maintain  satisfactory  electric  supply.  The
Company's Integrated Electric Resource Plan (IERP),  recommends a combination of
a peak load reduction demand-side  management program and a capacity purchase as
the most  economical  method of meeting this need.  The IERP  projects  that new
electric  generating  capacity  will need to be installed on Long Island to meet
peak  demand in the summer of 2001.  It is  anticipated  that such new  capacity
would be acquired through a competitive bidding process.

                                       49

<PAGE>

MERGER AGREEMENT WITH THE BROOKLYN UNION GAS COMPANY

On December 29, 1996, the Company and The Brooklyn  Union Gas Company  (Brooklyn
Union)  entered  into  an  Agreement  and  Plan  of  Exchange   (Share  Exchange
Agreement), pursuant to which the companies will be merged in a transaction that
will result in the formation of a new holding company.  The new holding company,
which has not yet been named, will serve approximately 2.2 million customers and
have  revenues  of  more  than  $4.5  billion.  The  merger  is  expected  to be
accomplished  through a  tax-free  exchange  of shares  and  accounted  for as a
pooling of interests.

The  description  of the Share  Exchange  Agreement  set forth  herein  does not
purport to be complete and is qualified in its entirety by the provisions of the
Share Exchange Agreement, filed as an exhibit to the Company's Current Report on
Form 8-K dated December 30, 1996.

The proposed  transaction,  which has been approved by both companies' boards of
directors,  would unite the  resources  of the  Company  with the  resources  of
Brooklyn Union. Brooklyn Union, with approximately 3,300 employees,  distributes
natural gas at retail,  primarily  in a territory  of  approximately  187 square
miles  which   includes  the   boroughs  of  Brooklyn  and  Staten   Island  and
approximately  two-thirds  of the  borough  of  Queens,  all in New  York  City.
Brooklyn Union has energy-related investments in gas exploration, production and
marketing  in the United  States and Canada,  as well as energy  services in the
United States, including cogeneration products,  pipeline transportation and gas
storage.

Under the terms of the proposed  transaction,  the Company's common  shareowners
will receive .803 shares (the Ratio) of the new holding  company's  common stock
for each share of the Company's common stock that they currently hold.  Brooklyn
Union  common  shareowners  will  receive  one share of common  stock of the new
holding  company for each common share of Brooklyn  Union they  currently  hold.
Shareowners of the Company will own approximately 66% of the common stock of the
new holding company while Brooklyn Union shareowners will own approximately 34%.
The proposed  transaction will have no effect on either company's debt issues or
outstanding preferred stock.

The Share Exchange  Agreement  contains certain covenants of the parties pending
the consummation of the transaction.  Generally, the parties must carry on their
businesses  in the  ordinary  course  consistent  with  past  practice,  may not
increase  dividends on common stock  beyond  specified  levels and may not issue
capital stock beyond certain limits.  The Share Exchange Agreement also contains
restrictions  on, among other  things,  charter and by-law  amendments,  capital
expenditures,  acquisitions,  dispositions,  incurrence of indebtedness, certain
increases in employee  compensation  and benefits,  and affiliate  transactions.
Accordingly,  the  Company's  ability  to engage in certain  activity  described
herein may be limited or prohibited by the Share Exchange Agreement.

                                       50

<PAGE>




Upon completion of the merger,  Dr. William J.  Catacosinos will become chairman
and chief executive  officer of the new holding  company;  Mr. Robert B. Catell,
currently  chairman and chief executive  officer of Brooklyn Union,  will become
president and chief operating officer of the new holding company. One year after
the closing, Mr. Catell will succeed Dr. Catacosinos as chief executive officer,
with Dr. Catacosinos  continuing as chairman.  The board of directors of the new
company will be composed of 15 members,  six from the Company, six from Brooklyn
Union and three additional persons  previously  unaffiliated with either company
and jointly selected by them.

The companies will continue their respective current dividend policies until the
closing,  consistent with the provisions of the Share Exchange Agreement.  It is
expected that the new holding company's dividend policy will be determined prior
to closing.

The merger is conditioned  upon, among other things,  the approval of the merger
by the holders of two-thirds of the  outstanding  shares of common stock of each
of the Company and  Brooklyn  Union and the receipt of all  required  regulatory
approvals.  The Company is unable to determine when or if all required approvals
will be obtained.

In 1995, the Long Island Power Authority  (LIPA),  an agency of the State of New
York (NYS), was requested by the Governor of NYS to develop a plan,  pursuant to
its authority  under NYS law, to provide an electric rate  reduction of at least
10%,  provide a framework  for long-term  competition  in power  production  and
protect property tax payers on Long Island.

The Share Exchange Agreement contemplates that discussions,  which are currently
in  progress,  will  continue  with  LIPA to  arrive  at an  agreement  mutually
acceptable to the Company, Brooklyn Union and LIPA, pursuant to which LIPA would
acquire certain assets or securities of the Company, the consideration for which
would inure to the benefit of the new holding company.  In the event that such a
transaction  is  completed,  the Ratio would become  .880.  In  connection  with
discussions  with LIPA,  LIPA has  indicated  that it may  exercise its power of
eminent domain over all or a portion of the Company's  assets or securities,  in
order to  achieve  its  objective  of  reducing  current  electric  rates,  if a
negotiated  agreement cannot be reached. The Company is unable to determine when
or if an agreement with LIPA will be reached,  or what action, if any, LIPA will
take if such an agreement is not reached.

RATE MATTERS

ELECTRIC

In 1995,  the Company  submitted a  compliance  filing  requesting  that the PSC
extend the provisions of its 1995 electric rate order,  discussed below, through
November  30,  1996.  This  filing was updated by the Company in August 1996 and
approved by the PSC in January 1997.

During 1996, the PSC instituted numerous initiatives intended to lower

                                       51

<PAGE>



electric rates on Long Island.  The Company  shares the PSC's concern  regarding
electric  rate  levels  and is  prepared  to  assist  the  PSC in  pursuing  any
reasonable opportunity to reduce electric rates. The initiatives instituted were
as follows:

   An  Order  to Show  Cause,  issued  in  February  1996,  to  examine  various
   opportunities to reduce the Company's electric rates;

   An Order,  issued  in April  1996,  expanding  the scope of the Order to Show
   Cause  proceeding in an effort to provide  "immediate  and  substantial  rate
   relief."  This  order  directed  the  Company  to file  financial  and  other
   information  sufficient  to provide a legal  basis for  setting new rates for
   both the single rate year (1997) and the three-year period 1997 through 1999;
   and

   An Order, issued in July 1996, to institute an expedited temporary rate phase
   in the Order to Show Cause  proceeding  to be conducted in parallel  with the
   ongoing phase concerning permanent rates.

The Order issued in July  requested that  interested  parties file testimony and
exhibits  sufficient  to  provide  a basis  for the PSC to  decide  whether  the
Company's  electric  rates should be made temporary and, if so, the proper level
of such  temporary  rates.  The Staff of the PSC  (Staff),  in  response to this
Order,  recommended  that the Company's rates be reduced on a temporary basis by
4.2% effective October 1, 1996, until the permanent rate case is decided. In its
filing, the Company sought to demonstrate that current electric rate levels were
appropriate  and that there was no  justification  for reducing  them.  Although
evidentiary  hearings on the Company's,  Staff's and other  interested  parties'
submissions  were  subsequently  held on an expedited basis to enable the PSC to
render a decision on the Company's rates, as of the date of this report, the PSC
has yet to take any action.

In September  1996, the Company  completed the filing of a multi-year  rate plan
(Plan) in  compliance  with the April 1996  Order.  Major  elements  of the Plan
include:  (i) a base rate  freeze for the  three-year  period  December  1, 1996
through  November 30,  1999;  (ii) an allowed  return on common  equity of 11.0%
through the term of the Plan with the Company fully retaining all earnings up to
12.66%,  and sharing  with the customer any  earnings  above  12.66%;  (iii) the
continuation of existing LRPP revenue and expense reconciliation  mechanisms and
performance  incentive  programs;  (iv)  crediting  all net  proceeds  from  the
Shoreham  property tax  litigation  to the RMC to reduce its balance;  and (v) a
mechanism to fully  recover any  outstanding  RMC balance at the end of the 1999
rate year through  inclusion in the Fuel Cost Adjustment  (FCA), over a two-year
period.

1995 Electric Rate Order

The basis of the 1995 Order included  minimizing  future electric rate increases
while continuing to provide for the recovery of the Company's  regulatory assets
and retaining  consistency with the Rate Moderation  Agreement's (RMA) objective
of restoring the Company to financial health.

                                       52

<PAGE>



The 1995 Order,  which became  effective  December 1, 1994,  froze base 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.

The LRPP, originally approved by the PSC in November 1991, contained three major
components:   (i)   revenue   reconciliation;   (ii)   expense   attrition   and
reconciliation;  and (iii) performance-based  incentives. In the 1995 Order, the
PSC 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 1995 Order,  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
1995 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  pass-through 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, 1996,  the Company earned 20 basis points,
or  approximately  $4.3  million,  net  of  tax  effects,  as a  result  of  its
performance under all incentive programs.  For the rate years ended November 30,
1995 and 1994, the Company earned 19 and 50 basis points,

                                       53

<PAGE>



respectively, or approximately $4.0 million and $9.2 million,  respectively, net
of tax effects, under the incentive programs in effect at those times.

The deferred balances resulting from the net margin and expense reconciliations,
and earned performance-based incentives are netted at the end of each rate year,
as established  under the LRPP and continued under the 1995 Order. The first $15
million of the total  deferral is recovered  from or credited to  ratepayers  by
increasing  or  decreasing  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,  1996,  the  amount to be  returned  to
customers   resulting   from   the   revenue   and   expense    reconciliations,
performance-based  incentive  programs and associated  carrying  charges totaled
$14.5 million. Consistent with the mechanics of the LRPP, it is anticipated that
the entire  balance of the deferral  will be used to reduce the RMC balance upon
approval by the PSC of the Company's  reconciliation  filing which was submitted
to the PSC in January  1997.  For the rate year ended  November  30,  1995,  the
Company  recorded a net deferred LRPP credit of approximately  $41 million.  The
first $15 million of the  deferral  was applied as a reduction  to the RMC while
the  remaining  portion of the  deferral  of $26  million  will be  returned  to
customers  through  the FCA when  approved  by the PSC.  For the rate year ended
November 30, 1994, the Company  recorded a net deferred charge of  approximately
$79 million. The first $15 million of the deferral was applied as an increase to
the  RMC  while  the  remaining  deferral  of $64  million  was  recovered  from
customers.

Another  mechanism of the LRPP  provides  that 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 years ended November
30,  1996  and  1995,   the  Company  earned  $9.1  million  and  $6.2  million,
respectively,  in excess of its allowed  return on common  equity.  These excess
earnings  were applied as  reductions  to the RMC. In 1994,  the Company did not
earn in excess of its allowed return on common equity.

The  Company  is  currently  unable to  predict  the  outcome of any of the rate
proceedings  currently before the PSC and their effect, if any, on the Company's
financial position, cash flows or results of operations.

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  provided  annual gas
rate increases of 4.7%, 3.8% and 3.2% for each of the three rate years beginning
December 1, 1993,  1994, and 1995,  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  settlement also provided that earnings in excess of a 10.6% return
on common equity be shared equally between the Company's firm gas

                                       54

<PAGE>



customers and its shareowners.  For the rate years ended November 30, 1996, 1995
and 1994,  the firm gas  customers'  portion  of gas  earnings  in excess of the
allowed return on common equity totaled  approximately  $10 million,  $1 million
and $7 million, respectively. In 1996, the Company was granted permission by the
PSC to apply the  customers'  portion of the gas excess  earnings and associated
carrying  charges  for the 1995 and 1994 rate years to the  recovery of deferred
costs  associated  with  postretirement  benefits  other than pensions and costs
incurred for  investigation  and  remediation  of  manufactured  gas plant (MGP)
sites.  The Company has  requested  that the same  treatment  be granted for the
disposition of the customers' portion of the 1996 rate year gas excess earnings.

The Company currently has no gas rate filings before the PSC and does not intend
to file a gas rate case during the current rate year,  unless  required to do so
in connection with the proposed merger with Brooklyn Union.


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 1996,  both the PSC and the Federal  Energy  Regulatory
Commission  (FERC)  continued  their  separate,  but  in  some  cases  parallel,
initiatives  with respect to developing a framework  for a competitive  electric
marketplace.

THE ELECTRIC INDUSTRY - STATE REGULATORY ISSUES

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.

As a result of the Competitive Opportunities  Proceedings,  in May 1996, the PSC
issued an order (Order) which stated its belief that introducing  competition to
the electric  industry in New York has the  potential to reduce  electric  rates
over time,  increase  customer choice and encourage  economic growth.  The Order
calls for a  competitive  wholesale  power  market to be in place by early  1997
which will be followed by the introduction of retail access for all customers by
early 1998.

The PSC stated that competition  should be transitioned on an individual company
basis, due to differences in individual service territories,  the level and type
of strandable  investments  (I.E.,  costs that  utilities  would have  otherwise
recovered through rates under traditional cost of service

                                       55

<PAGE>



regulation that, under market competition, would not be recoverable) and utility
specific financial conditions.

The Order  contemplates  that  implementation of competition will proceed on two
tracks.   The  Order   requires  that  each  major   electric   utility  file  a
rate/restructuring plan which is consistent with the PSC's policy and vision for
increased  competition.  Those  plans were  submitted  by  October  1, 1996,  in
compliance  with  the  Order.  However,  the  Company  was  exempted  from  this
requirement due to the PSC's separate  investigation  of the Company's rates and
LIPA's  examination  of  the  Company's   structure.   Since  October  1,  1996,
proceedings  have  commenced  for  the  five  electric   utilities  which  filed
restructuring  plans in accordance with track one and the Company has intervened
in each of these proceedings.

The PSC order also  anticipated  that  certain  other  filings  would be made on
October 1, 1996, by all New York State utilities,  to both the PSC and the FERC.
The filings were to address the  delineation of  transmission  and  distribution
facilities jurisdiction between the FERC or the PSC, a pricing of each company's
transmission  services,  and a joint filing by all the  utilities to address the
formation of an Independent  System  Operator (ISO) and the creation of a market
exchange that will establish  spot market prices.  Although there were extensive
collaborative meetings among the parties, it was not possible for the additional
filings  to be  completed  by  October  1, 1996.  While  these  discussions  are
continuing  in an  attempt  to narrow  the  differences  among the  parties,  on
December 31, 1996,  the NYPP members  submitted a compliance  filing to the FERC
which provides open membership and comparable  services to eligible  entities in
accordance with FERC Order 888,  discussed  below.  The New York State utilities
submitted the full ISO/Power  Exchange filing to the FERC, in January 1997 which
proposes to establish a competitive  wholesale marketplace in New York State for
electric energy and transmission pricing at market based rates.

The PSC envisions that a fully operational  wholesale competitive structure will
foster the expeditious movement to full retail competition.  The PSC's vision of
the retail  competitive  structure,  known as the Flexible  Retail Poolco Model,
consists  of: (i) the  creation of an ISO to  coordinate  the safe and  reliable
operation  of  electric  generation  and  transmission;  (ii) open access to the
transmission   system,   which  would  be  regulated  by  the  FERC;  (iii)  the
continuation  of a regulated  distribution  company to operate and  maintain the
distribution  system; (iv) the deregulation of energy/customer  services such as
meter reading and customer billing; (v) the ability of customers to choose among
suppliers  of  electricity;  and (vi) the  allowance  of  customers  to  acquire
electricity  either by  long-term  contracts,  purchases on the spot market or a
combination of the two.

One issue  discussed  in the Order that could  affect the Company is  strandable
investments.  The PSC  stated  in its  Order  that it is not  required  to allow
recovery  of all  prudently  incurred  investments,  that  it  has  considerable
discretion to set rates that balance  ratepayer and shareholder  interests,  and
that the amount of  strandable  investments  that a utility will be permitted to
recover  will  depend  on  the   particular   circumstances   of  each  utility.
Additionally, the Order provided that every

                                       56

<PAGE>



effort  should be made by  utilities  to  mitigate  these costs prior to seeking
recovery.

Certain aspects of the  restructuring  envisioned by the  PSC--particularly  the
PSC's apparent determinations that it may deny the utilities recovery of prudent
investments  made on  behalf  of the  public,  order  retail  wheeling,  require
divestiture of generation  assets and deregulate  certain  sectors of the energy
market--could,  if  implemented,  have a negative  impact on the  operations and
financial conditions of New York's investor-owned electric utilities,  including
the Company.

The  Company is party to a lawsuit  commenced  in  September  1996 by the Energy
Association  of New York State and the  state's  other  investor-owned  electric
utilities (collectively, Petitioners) against the PSC in New York Supreme Court,
Albany  County  (THE  ENERGY  ASSOCIATION  OF NEW YORK  STATE,  ET AL. V. PUBLIC
SERVICE  COMMISSION  OF THE STATE OF NEW YORK,  ET AL.).  The  Petitioners  have
requested  that  the  Court  declare  that  the  Order is  unlawful  or,  in the
alternative,  that the  Court  clarify  that the PSC's  statements  in the Order
constitute  simply a policy statement with no binding legal effect.  In November
1996, the Court issued a Decision and Order denying the Petitioners'  request to
invalidate  the Order.  Although  the Court  stated  that most of the Order is a
non-binding statement of policy, the Court rejected the Petitioners' substantive
challenges to the Order. In December 1996,  Petitioners filed a notice of appeal
with the  Third  Department  of the  Appellate  Division  of the New York  State
Supreme Court.  The litigation is ongoing and the Company is unable at this time
to predict  the  likelihood  of success or the impact of the  litigation  on the
Company's financial position, cash flows or results of operations. Oral argument
in the Appellate Division has not yet been scheduled, but a decision is expected
by the end of 1997.

THE ELECTRIC INDUSTRY - FEDERAL REGULATORY ISSUES

In April 1996, in response to its Notice of Proposed  Rulemaking issued in March
1995,  the FERC issued two orders  relating to the  development  of  competitive
wholesale electric markets.

Order 888 is a final rule on open transmission access and stranded cost recovery
and provides that the FERC has exclusive  jurisdiction over interstate wholesale
wheeling and that utility  transmission  systems must now be open to  qualifying
sellers and purchasers of power on a non-discriminatory basis.

Order 888  allows  utilities  to  recover  legitimate,  prudent  and  verifiable
stranded   costs   associated   with  wholesale   transmission,   including  the
circumstances  where full requirements  customers become wholesale  transmission
customers, such as where a municipality establishes its own electric system.

With respect to retail  wheeling,  the FERC concluded  that it has  jurisdiction
over  rates,  terms and  conditions  of  service,  but would  leave the issue of
recovery of the costs stranded by retail wheeling to the states.

                                       57

<PAGE>

Order 888 required  utilities to file open access tariffs under which they would
provide transmission services, comparable to those which they provide themselves
and to third parties on a non-discriminatory basis. Additionally, utilities must
use these same tariffs for their own wholesale sales. The Company filed its open
access tariff in July 1996.

In September  1996,  the FERC ordered Rate  Hearings on 28 utility  transmission
tariffs, including the Company's. On the basis of a preliminary review, the FERC
was not  satisfied  that the tariff rates were just and  reasonable.  Settlement
discussions  have  been  held  between  the  Company  and  various   intervenors
concerning  the Company's  transmission  rates.  In December  1996,  the parties
reached a tentative  settlement on the rate issues. The procedural  schedule was
suspended  pending  filing of the  settlement  agreement,  which is  anticipated
during the first quarter of 1997.  Non-rate issues associated with the Company's
open access tariff have not yet been addressed by the FERC.

Order  889,  which is a final rule on a  transmission  pricing  bulletin  board,
addresses  the rules and  technical  standards  for  operation of an  electronic
bulletin  board  that will make  available,  on a  real-time  basis,  the price,
availability  and  other  pertinent  information  concerning  each  transmission
utility's  services.  It also  addresses  standards  of conduct  to ensure  that
transmission  utilities  functionally  separate their transmission and wholesale
power merchant  functions to prevent  discriminatory  self-dealing.  In December
1996, the Company filed its standards of conduct in accordance with the Order.

With other  members of the  industry,  the Company has  participated  in several
joint petitions for rehearing and/or  clarification of the FERC's Orders 888 and
889.  Among other  issues,  these  petitions  address the FERC's  obligation  to
exercise its jurisdiction to provide for the recovery of strandable  investments
in any retail wheeling situations.  The outcome and timing of the FERC Orders on
rehearing are uncertain.

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 the state and  federal
regulatory  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," could then
require a  significant  write-down  of all or a  portion  of the  Company's  net
regulatory assets.

THE COMPANY'S SERVICE TERRITORY

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.  However,  the  changing  utility
regulatory environment has affected the Company by

                                       58

<PAGE>



requiring the Company to co-exist with state and federally mandated competitors.
These  competitors  are  non-utility   generators  (NUGS),  NYPA  and  Municipal
Distribution Agencies (MDAs).

The Public Utility Regulatory Policies Act of 1978 (PURPA), the goal of which is
to reduce the United  States'  dependency  on foreign oil, to  encourage  energy
conservation and to promote  diversification  of the fuel supply, has negatively
impacted  the  Company  through the  encouragement  of the NUG  industry.  PURPA
provides for the development of a new class of electric generators which rely on
either cogeneration technology or alternate fuels. Utilities are obligated under
PURPA to purchase the output of certain of these generators,  which are known as
qualified facilities (QFs).

In 1996,  the  Company  lost sales to NUGs  totaling  422  gigawatt-hours  (GWh)
representing  a  loss  in  electric  revenues  net of  fuel  (net  revenues)  of
approximately $34 million,  or 1.9% of the Company's net revenues.  In 1995, the
Company lost sales to NUGs totaling 366 GWh or approximately $28 million or 1.5%
of the Company's net revenues.

The increase in lost net revenues  resulted  principally  from the completion of
seven facilities that became  commercially  operational during 1996 and the full
year  operation of the IPP located at the State  University of New York at Stony
Brook, NY. The Company  estimates that in 1997, sales losses to NUGs will be 429
GWh, or approximately 1.8% 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 1996  approximated 218 megawatts (MW) and in early
1995  approximated  205 MW. The  increase was the result of the SUNY Stony Brook
facility  going on line in mid 1995.  The Company  estimates that purchases from
QFs  required  by federal  and state law cost the  Company  $63  million and $53
million  in 1996 and 1995,  respectively,  more than it would  have cost had the
Company generated this power.

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  continues to apply 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 within its service territory.


                                       59

<PAGE>



The Company  has also  experienced  a revenue  loss as a result of its policy of
voluntarily  providing  wheeling  of NYPA power for  economic  development.  The
Company  estimates that in 1996 and 1995 NYPA power displaced  approximately 417
GWh  and  429  GWh of  annual  energy  sales,  respectively.  Net  revenue  loss
associated with these volumes of sales is approximately $26 million,  or 1.4% of
the Company's 1996 net revenues,  and $30 million, or 1.6% of the Company's 1995
net revenues.  Currently,  the potential  loss of additional  load is limited by
conditions in the Company's transmission agreements with NYPA.

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 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 that is likely to increase as a result
of the  National  Energy  Policy Act of 1992  (NEPA).  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. NEPA does so by creating exempt wholesale generators that can sell power
in  wholesale  markets  without  the  regulatory  constraint  placed on  utility
generators  such as on the Company.  NEPA also expanded the FERC's  authority to
grant access to utility  transmission  systems to all parties who seek wholesale
wheeling  for  wholesale  competition.  While it should be noted that the FERC's
position favoring stranded cost recovery from retail turned wholesale  customers
will reduce utility risk from  municipalization,  significant  issues associated
with the removal of  restrictions on wholesale  transmission  system access have
yet to be resolved.

There are numerous  towns and villages in the Company's  service  territory that
are  considering  the  formation of a  municipally  owned and operated  electric
authority to replace the services currently provided by the Company.

In 1995,  Suffolk  County issued a request for proposal from suppliers for up to
300 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.  After the Company
challenged Suffolk County's  eligibility for such service, the County petitioned
the FERC to order the Company to provide the requested transmission service.

In December 1996, the FERC ordered the Company to provide transmission  services
to Suffolk  County to the extent  necessary  to  accommodate  proposed  sales to
customers  to which it was  providing  service on the date of  enactment of NEPA
(this Order could provide Suffolk County with the ability to import up to 200 MW
of power on a daily basis). The FERC reserved

                                       60

<PAGE>



decision on the  remaining 100 MW of Suffolk  County's  request until the County
identifies the ownership or control of  distribution  facilities that it alleges
qualifies  it for a wheeling  order to  Suffolk  County  customers  who were not
receiving service on the date of NEPA's enactment.  The Company may ask the FERC
to reconsider  their  decision once that decision  becomes  final,  which is not
expected for several  months.  The FERC has yet to determine the pricing of that
service.  As  previously  noted,  FERC  order 888  allows  utilities  to recover
legitimate,  prudent and  verifiable  stranded costs  associated  with wholesale
transmission,  including the  circumstances  where full  requirements  customers
become  wholesale   transmission   customers,   such  as  where  a  municipality
establishes its own electric 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 the FERC may take regarding any of these matters,  or the impact
on the Company's financial position, cash flows or results of operations 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  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.

ENVIRONMENTAL MATTERS

The Company is subject to federal,  state and local laws and regulations dealing
with air and  water  quality  and  other  environmental  matters.  Environmental
matters  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.  The Company  continually  monitors
its  activities  in order to  determine  the  impact  of its  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  (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 are believed to have produced manufactured
gas. 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.  Research is
underway  to  determine  the  existence  and  nature  of  operations  and  their
relationship, if any, to the Company or its predecessor companies.

                                       61

<PAGE>




The  Company  has entered  into  discussions  with the DEC which may lead to the
issuance  of one or more  Administrative  Consent  Orders  (ACO)  regarding  the
management of environmental  activities at these properties.  Although the exact
amount of the Company's remediation costs cannot yet be determined, based on the
findings of investigations at two of these six sites, estimates indicate that it
will cost  approximately $51 million to remediate all of these sites through the
year 2005.  Accordingly,  the Company has 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 $35 million  liability  reflects the present value of
the future  stream of payments to  investigate  and remediate  these sites.  The
Company used a risk-free rate of 7.25% to discount this obligation.

In December  1996,  the Company filed a complaint in the United States  District
Court for the Southern District of New York against 14 of the Company's insurers
which issued general comprehensive  liability (GCL) policies to the Company. The
Company is seeking  recovery  under the GCL policies  for the costs  incurred to
date and future costs  associated with the clean-up of the Company's  former MGP
sites and  Superfund  sites for which the Company  has been named a  potentially
responsible party (PRP). The Company is seeking a declaratory judgement that the
defendant  insurers are bound by the terms of the GCL  policies,  subject to the
stated coverage limits, to reimburse the Company for the remediation  costs. The
outcome of this proceeding cannot yet be determined.

The Company  has been  notified by the United  States  Environmental  Protection
Agency (EPA) that it is one of many 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),  which has been  completed  and is currently  being
reviewed  by the  EPA.  Under a PRP  participation  agreement,  the  Company  is
responsible  for 8.2% of the  costs  associated  with this  RI/FS.  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  cost to  remediate  this  site  based  upon  its  8.2%
responsibility under the RI/FS.

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 company named 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 and certain soil areas outside the buildings are contaminated with
PCBs.


                                       62

<PAGE>



In 1994,  the EPA requested  certain of the large PRPs,  which  include  several
other utilities, to form a group, sign an ACO, and conduct a remediation program
for the sites under the Toxic Substances Control Act, or in the alternative,  to
perform a Superfund cleanup for the sites. The EPA has 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 Company  intends to join a PRP
Group which includes other  utilities,  which has been organized for the purpose
of developing and implementing  acceptable  remediation  programs for the sites.
The Company is currently  unable to determine its share of the cost to remediate
these sites.

In  addition,  the Company  was  notified  that it is a PRP at a Superfund  site
located  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 remediation  expenses in the amount
of approximately $100,000 associated with removing PCB-contaminated soils from a
portion of the site which formerly contained electric transformers.  The Company
is unable to determine its share of costs of remediation at this site.

During 1996, the Connecticut Department of Environmental Protection (DEP) issued
a modification to an ACO previously  issued in connection with an  investigation
of an electric  transmission  cable  located  under the Long Island Sound (Sound
Cable) that is jointly owned by the Company and the Connecticut  Light and Power
Company (Owners).  The modified ACO requires the Owners to submit to the DEP and
DEC a series of reports and studies describing cable system condition, operation
and repair  practices,  alternatives  for cable  improvements or replacement and
environmental impacts associated with leaks of fluid into the Long Island Sound,
which have occurred from time to time. The Company continues to compile required
information  and coordinate  the  activities  necessary to perform these studies
and,  at the present  time,  is unable to  determine  the costs it will incur to
complete the  requirements  of the modified ACO or to comply with any additional
requirements.

Previously,  the U.S.  Attorney for the District of Connecticut had commenced an
investigation  regarding  occasional  releases of fluid from the Sound Cable, as
well as associated operating and maintenance practices. The Owners have provided
the U.S.  Attorney with all requested  documentation.  The Company believes that
all  activities  associated  with the response to  occasional  releases from the
Sound Cable were consistent with legal and regulatory requirements.

In  addition,  during  1996 the  Long  Island  Soundkeeper  Fund,  a  non-profit
organization,  filed a suit  against  the  Owners of the Sound  Cable in Federal
District  Court  in  Connecticut  alleging  that the  Sound  Cable  fluid  leaks
constitute  unpermitted discharges of pollutants in violation of the Clean Water
Act (CWA)  and that such  pollutants  present  a threat to the  environment  and
public health. The suit seeks, among other things, injunctive relief prohibiting
the Owners from  continuing  to operate the Sound Cable in alleged  violation of
the CWA and civil  penalties of $25,000 per day for each  violation from each of
the Owners.

                                       63

<PAGE>




In December 1996, a barge, owned and operated by a third party,  dropped anchor,
causing  extensive  damage to the Sound Cable and a release of dielectric  fluid
into the Long Island Sound.  Temporary  clamps and leak abaters have been placed
on the cables which have stopped the leaks. Permanent repairs are expected to be
undertaken in the late spring of 1997. The  preliminary  estimate of the cost of
these  repairs is $15 million.  The Company  intends to seek recovery from third
parties for all costs incurred by the Company as a result of this incident.  The
timing and amount of recovery,  if any,  cannot yet be determined.  In addition,
the Owners  maintain  insurance  coverage  for the Sound Cable which the Company
believes will be sufficient to cover any repair costs.  In any event,  costs not
reimbursed by a third party or not covered by insurance  will be shared  equally
by the Owners.

The Company believes that none of the  environmental  matters,  discussed above,
will have a material adverse impact on the Company's  financial  position,  cash
flows or results of  operations.  In  addition,  the Company  believes  that all
significant  costs  incurred  with respect to  environmental  investigation  and
remediation  activities,  not  recoverable  from  insurance  carriers,  will  be
recoverable through rates.

CONSERVATION SERVICES

The Company's 1996 Demand Side  Management  (DSM) Plan focused on the pursuit of
energy  efficiency  and peak load  reduction in a way that had minimal impact on
electric rate  increases.  To assure the success of this  strategy,  the Company
implemented a balanced and  cost-effective mix of DSM programs that continued to
represent a limited reliance on broad-based rebates and a concentrated  emphasis
on  programs  that  provided   education  and  information,   targeted  business
development, improved the efficiency of the Company's facilities, induced market
transformation  and provided  financing for energy  efficiency.  The Company was
successful in meeting the PSC energy penalty  threshold of 26.7 GWh (80% of 33.3
GWh goal) at a cost less than that provided for in electric rates.

In 1997, the Company plans to continue this strategy with an increased  emphasis
on programs which  facilitate  the retention,  attraction and expansion of major
commercial/industrial  customers.   Specifically  these  programs  will  provide
incentives to encourage companies to invest in  energy-efficiency  as a means to
remain,  expand or relocate to Long Island.  Overall,  they will help to improve
the economic climate on Long Island as well as the Company's  competitiveness as
an energy provider.  The 1997 Plan targets an annualized  energy savings of 28.7
GWh.  The Company  believes  that it will meet the target and avoid any earnings
penalty.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This report contains statements which, to the extent they are not recitations of
historical fact, constitute  "forward-looking  statements" within the meaning of
the Securities  Litigation Reform Act of 1995 (Reform Act). In this respect, the
words "estimate,"  "project,"  "anticipate,"  "expect,"  "intend," "believe" and
similar expressions are intended to

                                       64

<PAGE>



identify  forward-looking  statements.  All such forward-looking  statements are
intended to be subject to the safe harbor protection provided by the Reform Act.
A number of important  factors  affecting the  Company's  business and financial
results could cause actual results to differ materially from those stated in the
forward-looking  statements.  Those  factors  include the  proposed  merger with
Brooklyn  Union and a  possible  transaction  with LIPA as  discussed  under the
heading  "Merger  Agreement  with The  Brooklyn  Union Gas  Company",  state and
federal  regulatory rate  proceedings,  competition,  and certain  environmental
matters each as discussed herein.

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 Item  6:  Selected  Financial  Data.
Information  with regard to the Company's  business  segments for the last three
years is provided in Note 12 of Notes to Financial Statements.


                                       65

<PAGE>



ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                                                                          PAGE

        Balance Sheet at December 31, 1996 and 1995........................ 67

        Statement of Income for each of the three years in the
        period ended December 31, 1996..................................... 69

        Statement of Cash Flows for each of the three years in
        the period ended December 31, 1996................................. 70

        Statement of Retained Earnings for each of the three
        years in the period ended December 31, 1996........................ 71

        Statement of Capitalization at December 31, 1996 and
        1995............................................................... 71

        Notes to Financial Statements...................................... 73

        Report of Independent Auditors.....................................111

        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)............120


                                       66

<PAGE>

FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
BALANCE SHEET
---------------------------------------------------------------------------------
ASSETS                                                 (In thousands of dollars)
---------------------------------------------------------------------------------
at December 31                                            1996              1995
---------------------------------------------------------------------------------

<S>                                               <C>               <C>
UTILITY PLANT
Electric                                          $  3,882,297      $  3,786,540
Gas                                                  1,154,543         1,086,145
Common                                                 260,268           244,828
Construction work in progress                          112,184           100,521
Nuclear fuel in process and in reactor                  15,454            16,456
---------------------------------------------------------------------------------
                                                     5,424,746         5,234,490
Less - Accumulated depreciation
  and amortization                                   1,729,576         1,639,492
---------------------------------------------------------------------------------
Total Net Utility Plant                              3,695,170         3,594,998
---------------------------------------------------------------------------------

REGULATORY ASSETS
Base financial component
  (less accumulated amortization
  of $757,282 and $656,311)                          3,281,548         3,382,519
Rate moderation component                              402,213           383,086
Shoreham post-settlement costs                         991,795           968,999
Shoreham nuclear fuel                                   69,113            71,244
Unamortized cost of issuing securities                 194,151           222,567
Postretirement benefits other than pensions            360,842           383,642
Regulatory tax asset                                 1,772,778         1,802,383
Other                                                  199,879           229,809
---------------------------------------------------------------------------------
Total Regulatory Assets                              7,272,319         7,444,249
---------------------------------------------------------------------------------

NONUTILITY PROPERTY AND OTHER INVESTMENTS               18,597            16,030
---------------------------------------------------------------------------------

CURRENT ASSETS
Cash and cash equivalents                              279,993           351,453
Special deposits                                        38,266            63,412
Customer accounts receivable
  (less allowance for doubtful
  accounts of $25,000 and $24,676)                     255,801           282,218
LRPP receivable                                              -            74,281
Other accounts receivable                               65,764           107,387
Accrued unbilled revenues                              169,712           184,440
Materials and supplies at average cost                  55,789            63,595
Fuel oil at average cost                                53,941            32,090
Gas in storage at average cost                          73,562            53,076
Deferred tax asset                                     145,205           191,000
Prepayments and other current assets                     8,569             8,986
---------------------------------------------------------------------------------
Total Current Assets                                 1,146,602         1,411,938
---------------------------------------------------------------------------------

DEFERRED CHARGES                                        76,991            60,382
---------------------------------------------------------------------------------

TOTAL ASSETS                                     $ 12,209,679      $ 12,527,597
================================================================================
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS.

                                       67
<PAGE>

<TABLE>
<CAPTION>

CAPITALIZATION AND LIABILITIES                         (In thousands of dollars)
---------------------------------------------------------------------------------
at December 31                                            1996              1995
---------------------------------------------------------------------------------

<S>                                               <C>               <C>
CAPITALIZATION
Long-term debt                                    $  4,471,675      $  4,722,675
Unamortized discount on debt                           (14,903)          (16,075)
---------------------------------------------------------------------------------
                                                     4,456,772         4,706,600
---------------------------------------------------------------------------------

Preferred stock - redemption required                  638,500           639,550
Preferred stock - no redemption required                63,664            63,934
---------------------------------------------------------------------------------
Total Preferred Stock                                  702,164           703,484
---------------------------------------------------------------------------------

Common stock                                           603,921           598,277
Premium on capital stock                             1,127,971         1,114,508
Capital stock expense                                  (49,330)          (50,751)
Retained earnings                                      840,867           790,919
Treasury stock, at cost                                    (60)                -
---------------------------------------------------------------------------------
Total Common Shareowners' Equity                     2,523,369         2,452,953
---------------------------------------------------------------------------------

Total Capitalization                                 7,682,305         7,863,037
---------------------------------------------------------------------------------

REGULATORY LIABILITIES
Regulatory liability component                         198,398           277,757
1989 Settlement credits                                127,442           136,655
Regulatory tax liability                               102,887           116,060
Other                                                  146,852           132,891
---------------------------------------------------------------------------------
Total Regulatory Liabilities                           575,579           663,363
---------------------------------------------------------------------------------

CURRENT LIABILITIES
Current maturities of long-term debt                   251,000           415,000
Current redemption requirements of preferred stock       1,050             4,800
Accounts payable and accrued expenses                  289,141           260,879
LRPP payable                                            40,499            17,240
Accrued taxes (including federal income
  tax of $25,884 and $28,736)                           63,640            60,498
Accrued interest                                       160,615           158,325
Dividends payable                                       58,378            57,899
Class Settlement                                        55,833            45,833
Customer deposits                                       29,471            29,547
---------------------------------------------------------------------------------
Total Current Liabilities                              949,627         1,050,021
---------------------------------------------------------------------------------

DEFERRED CREDITS
Deferred federal income tax                          2,442,606         2,337,732
Class Settlement                                        98,497           129,809
Other                                                   32,105            34,499
---------------------------------------------------------------------------------
Total Deferred Credits                               2,573,208         2,502,040
---------------------------------------------------------------------------------

OPERATING RESERVES
Pensions and other postretirement benefits             381,996           396,490
Claims and damages                                      46,964            52,646
---------------------------------------------------------------------------------
Total Operating Reserves                               428,960           449,136
---------------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES                                -                 -
---------------------------------------------------------------------------------

TOTAL CAPITALIZATION AND LIABILITIES              $ 12,209,679      $ 12,527,597
=================================================================================
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS.

                                       68
<PAGE>

<TABLE>
<CAPTION>

STATEMENT OF INCOME                               (In thousands of dollars except per share amounts)
----------------------------------------------------------------------------------------------------
For year ended December 31                                      1996           1995            1994
----------------------------------------------------------------------------------------------------

<S>                                                      <C>            <C>             <C>
REVENUES
Electric                                                 $ 2,466,435    $ 2,484,014     $ 2,481,637
Gas                                                          684,260        591,114         585,670
----------------------------------------------------------------------------------------------------
Total Revenues                                             3,150,695      3,075,128       3,067,307
----------------------------------------------------------------------------------------------------

OPERATING EXPENSES
Operations - fuel and purchased power                        963,251        834,979         847,986
Operations - other                                           381,076        383,238         406,014
Maintenance                                                  118,135        128,155         134,640
Depreciation and amortization                                153,925        145,357         130,664
Base financial component amortization                        100,971        100,971         100,971
Rate moderation component amortization                       (24,232)        21,933         197,656
Regulatory liability component amortization                  (79,359)       (79,359)        (79,359)
1989 Settlement credits amortization                          (9,214)        (9,214)         (9,214)
Other regulatory amortization                                127,288        161,605           4,328
Operating taxes                                              472,076        447,507         406,895
Federal income tax - current                                  42,197         14,596          10,784
Federal income tax - deferred and other                      168,000        193,742         170,997
----------------------------------------------------------------------------------------------------
Total Operating Expenses                                   2,414,114      2,343,510       2,322,362
----------------------------------------------------------------------------------------------------
Operating Income                                             736,581        731,618         744,945
----------------------------------------------------------------------------------------------------

OTHER INCOME AND (DEDUCTIONS)
Rate moderation component carrying charges                    25,259         25,274          32,321
Other income and deductions, net                              19,197         34,400          35,343
Class Settlement                                             (20,772)       (21,669)        (22,730)
Allowance for other funds used during construction             2,888          2,898           2,716
Federal income tax - deferred and other                          940          2,800           5,069
----------------------------------------------------------------------------------------------------
Total Other Income and (Deductions)                           27,512         43,703          52,719
----------------------------------------------------------------------------------------------------
Income Before Interest Charges                               764,093        775,321         797,664
----------------------------------------------------------------------------------------------------

INTEREST CHARGES
Interest on long-term debt                                   384,198        412,512         437,751
Other interest                                                67,130         63,461          62,345
Allowance for borrowed funds used during construction         (3,699)        (3,938)         (4,284)
----------------------------------------------------------------------------------------------------
Total Interest Charges                                       447,629        472,035         495,812
----------------------------------------------------------------------------------------------------

NET INCOME                                                   316,464        303,286         301,852
Preferred stock dividend requirements                         52,216         52,620          53,020
----------------------------------------------------------------------------------------------------

EARNINGS FOR COMMON STOCK                                $   264,248    $   250,666     $   248,832
====================================================================================================

AVERAGE COMMON SHARES OUTSTANDING (000)                      120,361        119,195         115,880
----------------------------------------------------------------------------------------------------

EARNINGS PER COMMON SHARE                                $      2.20    $      2.10     $      2.15
====================================================================================================

DIVIDENDS DECLARED PER COMMON SHARE                      $      1.78    $      1.78     $      1.78
----------------------------------------------------------------------------------------------------
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.

                                       69
<PAGE>

<TABLE>
<CAPTION>

STATEMENT OF CASH FLOWS                                                 (In thousands of dollars)
-------------------------------------------------------------------------------------------------
For year ended December 31                                      1996          1995          1994
-------------------------------------------------------------------------------------------------
<S>                                                     <C>            <C>           <C>
OPERATING ACTIVITIES
Net Income                                              $    316,464   $   303,286   $   301,852
   cash provided by operating activities
  Depreciation and amortization                              153,925       145,357       130,664
  Base financial component amortization                      100,971       100,971       100,971
  Rate moderation component amortization                     (24,232)       21,933       197,656
  Regulatory liability component amortization                (79,359)      (79,359)      (79,359)
  1989 Settlement credits amortization                        (9,214)       (9,214)       (9,214)
  Other regulatory amortization                              127,288       161,605         4,328
  Rate moderation component carrying charges                 (25,259)      (25,274)      (32,321)
  Amortization of cost of issuing and redeeming securities    34,611        39,589        46,237
  Class Settlement                                            20,772        21,669        22,730
  Provision for doubtful accounts                             23,119        17,751        19,542
  Federal income tax - deferred and other                    167,060       190,942       165,928
  Other                                                       66,624        61,576        46,531
Changes in operating assets and liabilities
  Accounts receivable                                         69,215       (67,213)      (17,353)
  Class Settlement                                           (42,084)      (33,464)      (30,235)
  Accrued unbilled revenues                                   14,728       (20,061)        5,663
  Accounts payable and accrued expenses                       28,258        19,100       (44,598)
  Other                                                      (50,574)      (77,194)        6,727
-------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities                    892,313       772,000       835,749
-------------------------------------------------------------------------------------------------

INVESTING ACTIVITIES

Construction and nuclear fuel expenditures                  (239,896)     (243,586)     (276,954)
Shoreham post-settlement costs                               (51,722)      (70,589)     (167,367)
Other investing activities                                    (4,806)        8,019        (1,349)
-------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities                       (296,424)     (306,156)     (445,670)
-------------------------------------------------------------------------------------------------

FINANCING ACTIVITIES

Proceeds from issuance of securities                          18,837        68,726       449,434
Redemption of securities                                    (419,800)     (104,800)     (639,858)
Common stock dividends paid                                 (213,753)     (211,630)     (205,086)
Preferred stock dividends paid                               (52,264)      (52,667)      (52,927)
Other financing activities                                      (369)          529        (4,723)
-------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities                       (667,349)     (299,842)     (453,160)
-------------------------------------------------------------------------------------------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS   $     (71,460)  $   166,002   $   (63,081)
=================================================================================================
Cash and cash equivalents at January 1                 $     351,453   $   185,451   $   248,532
Net (decrease) increase in cash and cash equivalents         (71,460)      166,002       (63,081)
-------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT DECEMBER 31               $     279,993   $   351,453   $   185,451
=================================================================================================


Interest paid, before reduction for the allowance
   for borrowed funds used during constuction          $     404,663   $   427,988   $   446,340
Federal income tax - paid                              $      45,050   $    14,200   $    10,780
-------------------------------------------------------------------------------------------------
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
                                       70
<PAGE>

<TABLE>
<CAPTION>

STATEMENT OF RETAINED EARNINGS                               (In thousands of dollars)
---------------------------------------------------------------------------------------
                                                          1996        1995        1994
---------------------------------------------------------------------------------------

<S>                <C>                             <C>           <C>         <C>
Balance at January 1                               $   790,919   $ 752,480   $ 711,432
Net income for the year                                316,464     303,286     301,852
---------------------------------------------------------------------------------------
                                                     1,107,383    1,055,766   1,013,284
Deductions
Cash dividends declared on common stock                214,255     212,181     207,794
Cash dividends declared on preferred stock              52,240      52,647      53,046
Other                                                       21          19         (36)
---------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31                             $   840,867   $ 790,919   $ 752,480
=======================================================================================
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS.


<TABLE>
<CAPTION>
STATEMENT OF CAPITALIZATION                                           Shares Issued                (In thousands of dollars)
-------------------------------------------------------------------------------------------------------------------------------
At December 31                                                   1996              1995              1996             1995
------------------------------------------------------------------------------------------------------------------------------

<S>                                                          <C>               <C>                <C>           <C>       
COMMON SHAREOWNERS' EQUITY
Common stock, $5.00 par value                                120,784,277       119,655,441        $  603,921    $     598,277       
Premium on capital stock                                                                           1,127,971        1,114,508
Capital stock expense                                                                                (49,330)         (50,751)
Retained earnings                                                                                    840,867          790,919
Treasury stock, at cost                                            3,485                 -               (60)               -
------------------------------------------------------------------------------------------------------------------------------
TOTAL COMMON SHAREOWNERS' EQUITY                                                                   2,523,369        2,452,953
------------------------------------------------------------------------------------------------------------------------------

PREFERRED STOCK - REDEMPTION REQUIRED
Par value $100 per share
      7.40% Series L                                             161,000           171,500            16,100           17,150
      8.50% Series R                                                   -            37,500                 -            3,750
      7.66% Series CC                                            570,000           570,000            57,000           57,000
Less - Sinking fund requirement                                                                        1,050            4,800
------------------------------------------------------------------------------------------------------------------------------
                                                                                                      72,050           73,100
------------------------------------------------------------------------------------------------------------------------------
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                                                          638,500          639,550
------------------------------------------------------------------------------------------------------------------------------

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                              16,637            19,336             1,664            1,934
------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required                                                        63,664           63,934
------------------------------------------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK                                                                             $  702,164    $     703,484    
------------------------------------------------------------------------------------------------------------------------------
</TABLE>
                                       71
<PAGE>

<TABLE>
<CAPTION>
                                                                                                  (In thousands of dollars)
------------------------------------------------------------------------------------------------------------------------------
At December 31                                  Maturity          Interest Rate      Series              1996             1995
------------------------------------------------------------------------------------------------------------------------------

<S>                                      <C>                           <C>             <C>       <C>              <C>
GENERAL AND REFUNDING BONDS
                                               May 1, 1996             8 3/4%                              -          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                                                                  1,536,000        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             3.25%           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             4.05%           1993 A         50,000           50,000
                                          November 1, 2023             4.00%           1993 B         50,000           50,000
                                           October 1, 2024             4.00%           1994 A         50,000           50,000
                                            August 1, 2025             4.00%           1995 A         50,000           50,000
------------------------------------------------------------------------------------------------------------------------------
Total Authority Financing Notes                                                                      916,675          916,675
------------------------------------------------------------------------------------------------------------------------------
Unamortized Discount on Debt                                                                         (14,903)         (16,075)
------------------------------------------------------------------------------------------------------------------------------
Total                                                                                              4,707,772        5,121,600
Less Current Maturities                                                                              251,000          415,000
------------------------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT                                                                               4,456,772        4,706,600
------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION                                                                             $ 7,682,305      $ 7,863,037       
==============================================================================================================================
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS.

                                       72
<PAGE>



Note 1. Summary of Significant Accounting Policies

NATURE OF OPERATIONS

Long  Island  Lighting  Company  (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  1996  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  1.03  million  electric  customers  of which
approximately 921,000 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  460,000 gas customers,  412,000 of which
are residential, accounting for 61% of the gas revenues, with the balance of the
gas  revenues  made up by the  commercial/industrial  customers  and  off-system
sales.

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. For
a further discussion of the competitive issues facing the Company, see Note 11.

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

                                       73

<PAGE>



Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation".  This statement  recognizes the economic  ability of regulators,
through  the  ratemaking   process,  to  create  future  economic  benefits  and
obligations affecting rate-regulated companies. Accordingly, the Company records
these  future  economic  benefits  and  obligations  as  regulatory  assets  and
regulatory liabilities.

Regulatory assets represent probable future revenues  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  $6.7  billion  and $6.8  billion at  December  31, 1996 and 1995,
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  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 11, the PSC has made a decision in the  Competitive
Opportunities  Proceedings  to transition  the electric  industry to a wholesale
power market in early 1997 followed by the introduction of retail access for all
customers by early 1998. 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,  a  significant  write-down  of all or a portion  of the  Company's
existing   regulatory  assets  and  liabilities  could  result.  For  additional
information  respecting  the Company's  Shoreham-related  assets,  see below and
Notes 2, 3 and 11.

In 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

                                       74

<PAGE>



amends  SFAS No. 71.  Under  SFAS No.  121,  costs  which  were  capitalized  in
accordance  with  regulatory  practices,  because it was  probable  that  future
recovery  would be allowed by the  regulator,  must be charged  against  current
period  earnings if it appears that the criterion for  capitalization  no longer
applies.  The  carrying  amount of such  assets  would be reduced by amounts for
which  recovery is unlikely.  SFAS No. 121 also provides for the  restoration of
previously  disallowed costs that are subsequently allowed by a regulator.  With
respect to assets recognized under SFAS No. 71 and all other long-lived  assets,
the adoption of SFAS No. 121 did not have an effect on the  Company's  financial
position, cash flows 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,  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 a forty-year period 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

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

Principally reflects the unamortized portion of Shoreham nuclear fuel which

                                       75

<PAGE>



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

Represents  the  unamortized  premiums or discounts and expenses  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, "Employers' Accounting
for Postretirement  Benefits Other Than Pensions",  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, 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  electric   ratepayers  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.



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1989 SETTLEMENT CREDITS

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  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 the FERC on a portion of construction work in progress. The average
annual AFC rate, without giving effect to compounding, was 9.02% 9.36% and 9.18%
for the years 1996, 1995 and 1994, 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 1996,
1995 and 1994.  Depreciation  for gas properties was equivalent to approximately
2.0% of respective  average  depreciable plant costs for each of the years 1996,
1995 and 1994.

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.

LRPP RECEIVABLE/PAYABLE

Represents the current portion of amounts recoverable from or due to

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ratepayers   that  result   from  the   revenue  and  expense   reconciliations,
performance-based  incentives  and  associated  carrying  charges as established
under the LILCO Ratemaking and Performance Plan (LRPP).  For further  discussion
of the LRPP, see Note 3.

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 rate  structure  provides for a weather  normalization  clause
which 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.


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For ratemaking  purposes,  the Company provides deferred federal income tax with
respect to certain  differences  between  income before income tax for financial
reporting  purposes and taxable  income for federal  income tax purposes.  Also,
certain  accumulated  deferred federal income tax is 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 $25 million.  Storm losses which are
outside of 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.

RECLASSIFICATIONS

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


NOTE 2. THE 1989 SETTLEMENT

In February  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.

In  February  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

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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, 1996, Shoreham  post-settlement  costs totaled
approximately  $1.103 billion,  consisting of $536 million of property taxes and
payments-in-lieu-of-taxes,  and $567  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.


NOTE 3. RATE MATTERS

ELECTRIC

In 1995,  the Company  submitted a  compliance  filing  requesting  that the PSC
extend the provisions of its 1995 electric rate order,  discussed below, through
November  30,  1996.  This  filing was updated by the Company in August 1996 and
approved by the PSC in January 1997.

During 1996, the PSC instituted numerous  initiatives intended to lower electric
rates on Long Island.  The Company shares the PSC's concern  regarding  electric
rate  levels  and is  prepared  to assist  the PSC in  pursuing  any  reasonable
opportunity  to  reduce  electric  rates.  The  initiatives  instituted  were as
follows:

      An Order to Show  Cause,  issued in  February  1996,  to  examine  various
      opportunities to reduce the Company's electric rates;

      An Order,  issued in April 1996,  expanding the scope of the Order to Show
      Cause  proceeding in an effort to provide  "immediate and substantial rate
      relief."  This order  directed  the  Company to file  financial  and other
      information  sufficient to provide a legal basis for setting new rates for
      both the single rate year (1997) and the  three-year  period 1997  through
      1999; and

      An Order,  issued in July 1996, to institute an expedited  temporary  rate
      phase in the Order to Show Cause  proceeding  to be  conducted in parallel
      with the ongoing phase concerning permanent rates.

The Order issued in July  requested that  interested  parties file testimony and
exhibits  sufficient  to  provide  a basis  for the PSC to  decide  whether  the
Company's  electric  rates should be made temporary and, if so, the proper level
of such  temporary  rates.  The Staff of the PSC  (Staff),  in  response to this
Order,  recommended  that the Company's rates be reduced on a temporary basis by
4.2% effective October 1, 1996, until the permanent rate case is decided. In its
filing, the Company sought to demonstrate

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that  current  electric  rate  levels  were  appropriate  and that  there was no
justification for reducing them. Although evidentiary hearings on the Company's,
Staff's and other interested  parties'  submissions were subsequently held on an
expedited  basis to enable the PSC to render a decision on the Company's  rates,
as of the date of this report, the PSC has yet to take any action.

In September  1996, the Company  completed the filing of a multi-year  rate plan
(Plan) in  compliance  with the April 1996  Order.  Major  elements  of the Plan
include:  (i) a base rate  freeze for the  three-year  period  December  1, 1996
through  November 30,  1999;  (ii) an allowed  return on common  equity of 11.0%
through the term of the Plan with the Company fully retaining all earnings up to
12.66%,  and sharing  with the customer any  earnings  above  12.66%;  (iii) the
continuation of existing LRPP revenue and expense reconciliation  mechanisms and
performance  incentive  programs;  (iv)  crediting  all net  proceeds  from  the
Shoreham  property tax  litigation  to the RMC to reduce its balance;  and (v) a
mechanism to fully  recover any  outstanding  RMC balance at the end of the 1999
rate year through  inclusion in the Fuel Cost Adjustment  (FCA), over a two-year
period.

1995 Electric Rate Order

The basis of the 1995 Order included  minimizing  future electric rate increases
while continuing to provide for the recovery of the Company's  regulatory assets
and retaining  consistency  with the RMA's objective of restoring the Company to
financial health. The 1995 Order, which became effective December 1, 1994, froze
base 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.

The LRPP, originally approved by the PSC in November 1991, contained three major
components:   (i)   revenue   reconciliation;   (ii)   expense   attrition   and
reconciliation;  and (iii) performance-based  incentives. In the 1995 Order, the
PSC 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 1995 Order,  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.


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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
1995 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  pass-through 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, 1996,  the Company earned 20 basis points,
or  approximately  $4.3  million,  net  of  tax  effects,  as a  result  of  its
performance under all incentive programs.  For the rate years ended November 30,
1995 and 1994,  the  Company  earned 19 and 50 basis  points,  respectively,  or
approximately $4.0 million and $9.2 million,  respectively,  net of tax effects,
under the incentive programs in effect at those times.

The deferred balances resulting from the net margin and expense reconciliations,
and earned performance-based incentives are netted at the end of each rate year,
as established  under the LRPP and continued under the 1995 Order. The first $15
million of the total  deferral is recovered  from or credited to  ratepayers  by
increasing  or  decreasing  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,  1996,  the  amount to be  returned  to
customers   resulting   from   the   revenue   and   expense    reconciliations,
performance-based  incentive  programs and associated  carrying  charges totaled
$14.5 million. Consistent with the mechanics of the LRPP, it is anticipated that
the entire  balance of the deferral  will be used to reduce the RMC balance upon
approval by the PSC of the Company's  reconciliation  filing which was submitted
to the PSC in January  1997.  For the rate year ended  November  30,  1995,  the
Company  recorded a net deferred LRPP credit of approximately  $41 million.  The
first $15 million of the  deferral  was applied as a reduction  to the RMC while
the  remaining  portion of the  deferral  of $26  million  will be  returned  to
customers  through  the FCA when  approved  by the PSC.  For the rate year ended
November 30, 1994, the Company  recorded a net deferred charge of  approximately
$79 million. The first $15 million of the deferral was applied as an increase to
the  RMC  while  the  remaining  deferral  of $64  million  was  recovered  from
customers.

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Another  mechanism of the LRPP  provides  that 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 years ended November
30,  1996  and  1995,   the  Company  earned  $9.1  million  and  $6.2  million,
respectively,  in excess of its allowed  return on common  equity.  These excess
earnings  were applied as  reductions  to the RMC. In 1994,  the Company did not
earn in excess of its allowed return on common equity.

The  Company  is  currently  unable to  predict  the  outcome of any of the rate
proceedings  currently before the PSC and their effect, if any, on the Company's
financial position, cash flows or results of operations.

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  provided  annual gas
rate increases of 4.7%, 3.8% and 3.2% for each of the three rate years beginning
December 1, 1993,  1994, and 1995,  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  settlement also provided 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, 1996, 1995 and 1994, the
firm gas  customers'  portion of gas earnings in excess of the allowed return on
common  equity  totaled  approximately  $10 million,  $1 million and $7 million,
respectively.  In 1996,  the Company was granted  permission by the PSC to apply
the  customers'  portion  of the gas excess  earnings  and  associated  carrying
charges  for the 1995 and 1994 rate  years to the  recovery  of  deferred  costs
associated with  postretirement  benefits other than pensions and costs incurred
for  investigation  and remediation of manufactured  gas plant (MGP) sites.  The
Company has requested that the same treatment be granted for the  disposition of
the customers' portion of the 1996 rate year gas excess earnings.

The Company currently has no gas rate filings before the PSC and does not intend
to file a gas rate case during the current rate year,  unless  required to do so
in connection with the proposed merger with Brooklyn Union.


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.


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The  Class  Settlement  provides  the  Company's  electric  customers  with rate
reductions  aggregating  $390 million that are being reflected as adjustments to
their monthly electric bills over a ten-year period which began on June 1, 1990.
Upon its  effectiveness,  the  Company  recorded  its  liability  for the  Class
Settlement  on a present  value  basis at $170  million.  The  Class  Settlement
Obligation  at December  31, 1996  reflects the present  value of the  remaining
reductions  to be refunded to customers.  The remaining  reductions to customers
bills, amounting to approximately $201 million as of December 31, 1996, consists
of  approximately  $21 million for the five-month  period  beginning  January 1,
1997, and $60 million for each of the 12-month  periods  beginning June 1, 1997,
1998 and 1999.


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

The Company has an undivided 18% 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%). The Company's share of the
rated  capability  is  approximately  206 MW. The  Company's  net utility  plant
investment,  excluding  nuclear fuel,  was  approximately  $715 million and $740
million at December 31, 1996 and 1995,  respectively.  The accumulated provision
for  depreciation,  excluding  decommissioning  costs,  was  approximately  $169
million and $153 million at December 31, 1996 and 1995, respectively. Generation
from  NMP2  and  operating  expenses  incurred  by NMP2 are  shared  in the same
proportions as the cotenants'  respective  ownership  interests.  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 1996, 1995 and 1994, this
totaled $1.4 million, $1.2 million, and $1.4 million, respectively.

NUCLEAR PLANT DECOMMISSIONING

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. The Company's share of decommissioning  costs, based upon a "Site-Specific"
1995 study (1995  study),  is estimated to be $368 million in 2026 dollars ($148
million in 1996  dollars).  The  Company's  estimate for  decommissioning  costs
decreased in 1996 as compared to 1995  principally as a result of a reduction in
the estimated  annual  inflation  factor.  The Company's  share of the estimated
decommissioning  costs is currently  being provided for in electric rates and is
being  charged to operations  as  depreciation  expense over the service life of
NMP2. The amount of

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decommissioning  costs recorded as  depreciation  expense in 1996, 1995 and 1994
was $3.9 million, $2.3 million and $1.6 million,  respectively.  The accumulated
decommissioning  costs  collected in rates through  December 31, 1996,  1995 and
1994 amounted to $14.9 million, $11.0 million and $8.7 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 76%
of the total  decommissioning  costs. These funds comply with regulations issued
by the NRC and the FERC  governing the funding of nuclear plant  decommissioning
costs.  The Company's  policy is to make  quarterly  contributions  to the funds
based  upon the  amount of  decommissioning  costs  reflected  in  rates.  As of
December  31,  1996,  the  balance  in these  funds,  including  reinvested  net
earnings,  was  approximately  $15.3 million.  These amounts are included on the
Company's Balance Sheet in Nonutility Property and Other Investments.  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".  Under the  provisions of the exposure  draft,  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.  If the Company
was  required to record the present  value of its share of NMP2  decommissioning
costs on its Balance  Sheet as of December 31, 1996,  the Company  would have to
recognize  a  liability   and   corresponding   increase  to  nuclear  plant  of
approximately $54 million.

NUCLEAR PLANT INSURANCE

NMPC procures public liability and property  insurance for NMP2, and the Company
reimburses NMPC for its 18% share of those costs.

The  Price-Anderson  Act mandates  that nuclear  power plants  secure  financial
protection in the event of a nuclear  accident.  This protection must consist of
two levels.  The primary level  provides  liability  insurance  coverage of $200
million (the maximum amount  available) in the event of a nuclear  accident.  If
claims exceed that amount,  a second level of  protection is provided  through a
retrospective  assessment of all licensed operating  reactors.  Currently,  this
"secondary  financial  protection"  subjects each of the 110 presently  licensed
nuclear  reactors in the United States to a  retrospective  assessment up to $76
million for each nuclear

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incident,  payable at a rate not to exceed $10 million per year.  The  Company's
interest in NMP2 could expose it to a maximum  potential  loss of $13.6 million,
per  incident,  through  assessments  of $1.8 million per year in the event of a
serious nuclear  accident at NMP2 or another  licensed U.S.  commercial  nuclear
reactor.  These assessments are subject to periodic  inflation indexing and to a
5% surcharge if funds prove insufficient to pay claims.

NMPC has also procured $500 million primary nuclear property  insurance with the
Nuclear Insurance Pools and approximately $2.3 million of additional  protection
(including decontamination costs) in excess of the primary layer through Nuclear
Electric Insurance Limited (NEIL).  Each member of NEIL,  including the Company,
is also subject to retrospective  premium adjustments in the event losses exceed
accumulated reserves. For its share of NMP2, the Company could be assessed up to
approximately $1.9 million per loss. This level of insurance is in excess of the
NRC's required $1.06 billion of coverage.

The Company has  obtained  insurance  coverage  from NEIL for the extra  expense
incurred in purchasing  replacement power during prolonged  accidental  outages.
Under this program,  should losses exceed the accumulated reserves of NEIL, each
member, including the Company, would be liable for its share of deficiency.  The
Company's  maximum  liability per incident under the replacement power coverage,
in the event of a deficiency, is approximately $842,000.

RECENT ACTIONS OF THE NRC

In October 1996, NMPC,  along with other  companies,  received a letter from the
NRC  requiring  them to provide the NRC with  information  on the  "adequacy and
availability"  of design basis  documentation on their nuclear plants within 120
days. Such  information  will be used by the NRC to verify that companies are in
compliance   with  the  terms  and  conditions  of  their   license(s)  and  NRC
regulations. In addition, it will allow the NRC to determine if other inspection
activities or enforcement actions should be taken on a particular company.  NMPC
plans to respond to the NRC by the February 9, 1997 due date.

NMPC  believes  that the NRC is becoming  more  stringent  as  indicated by this
request and that a direct  cost  impact on  companies  with  nuclear  plants may
result.  The  Company  is unable to  predict  how such a higher  risk  operating
environment  may  affect  its  financial  position,  cash  flows or  results  of
operations.


NOTE 6. CAPITAL STOCK

COMMON STOCK

The  Company  has  150,000,000  shares  of  authorized  common  stock,  of which
120,784,277  were issued and 3,485  shares were held in Treasury at December 31,
1996. The Company has 1,678,208 shares reserved for sale through its

                                       86

<PAGE>



Employee  Stock  Purchase  Plan,  2,728,486  shares  committed to the  Automatic
Dividend  Reinvestment  Plan and 97,093  shares  reserved for  conversion of the
Series I Convertible Preferred Stock at a rate of $17.15 per share. In addition,
in connection  with the Share Exchange  Agreement,  as discussed in Note 10, the
Company has granted Brooklyn Union the right,  under certain  circumstances,  to
purchase 23,981,964 shares of common stock at a price of $19.725 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, 1996 and 1995 amounted to approximately $637 million
and $598  million,  respectively,  compared  to their  carrying  amounts of $640
million and $644 million, respectively. For a further discussion on the basis of
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:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
              REDEMPTION PROVISION                             
              --------------------               NUMBER        REDEMPTION
 SERIES   BEGINNING           ENDING           OF SHARES          PRICE
--------------------------------------------------------------------------------
    <S>    <C>                <C>               <C>               <C> 
    L       7/31/79            7/31/11           10,500           $100
    NN       3/1/99             3/1/19           77,700             25
    UU     10/15/99           10/15/19          112,000             25
================================================================================
</TABLE>

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 is $1.1  million in 1997 and 1998 and $5.8
million in each of the years 1999, 2000 and 2001.

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:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
                           REDEMPTION             NUMBER OF         REDEMPTION
     SERIES                  DATE                  SHARES            AMOUNTS
--------------------------------------------------------------------------------
<S>                         <C>                 <C>                <C>         
$1.67 Series GG             3/1/99                 880,000         $ 22,000,000
7.95% Series AA             6/1/00              14,520,000          363,000,000
7.05% Series QQ             5/1/01               3,464,000           86,600,000
7.66% Series CC             8/1/02                 570,000           57,000,000
==============================================================================
</TABLE>

                                       87

<PAGE>


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, 1996, the call prices
were as follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------
        SERIES                                           CALL PRICE
--------------------------------------------------------------------
    <C>                                                     <C> 
    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
====================================================================
</TABLE>


PREFERENCE STOCK

At  December   31,   1996,   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.


NOTE 7. LONG-TERM DEBT

G&R MORTGAGE

The General and Refunding (G&R) Bonds are 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 1996, due not later than
June 30, 1997, is estimated at $25 million.  The Company expects to satisfy this
requirement  with  retired G&R Bonds,  property  additions,  or any  combination
thereof.

1989 REVOLVING CREDIT AGREEMENT

The Company has available  through  October 1, 1997, $250 million under its 1989
Revolving Credit  Agreement (1989 RCA). In July 1996, at the Company's  request,
the amount committed by the banks participating in the facility was reduced from
$300  million  to $250  million.  This line of credit is secured by a first lien
upon the Company's accounts receivable and fuel oil inventories. At December 31,
1996,  no  amounts  were  outstanding  under the 1989  RCA.  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, 1997.

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-

                                       88

<PAGE>



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.

Tender  requirements  of Authority  Financing Notes at December 31, 1996 were as
follows:
<TABLE>
<CAPTION>
                                                     (In thousands of dollars)
--------------------------------------------------------------------------------
          Interest
            Rate        Series       Principal                Tendered
--------------------------------------------------------------------------------
<S>         <C>        <C>           <C>               <C>                                   
PCRBs       8 1/4%     1982          $17,200           Tendered every three
                                                       years, next tender
                                                       October 1997
             3.25%     1985 A,B      150,000           Tendered annually on
                                                       March 1

EFRBs        4.05%     1993 A         50,000           Tendered weekly
             4.00%     1993 B         50,000           Tendered weekly
             4.00%     1994 A         50,000           Tendered weekly
             4.00%     1995 A         50,000           Tendered weekly
================================================================================
</TABLE>


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:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
                        Series                         Expiration Date
--------------------------------------------------------------------------------
<S>                     <C>                            <C>  
PCRBs                   1985 A,B                        3/16/99
EFRBs                   1993 A,B                       11/17/99
                        1994 A                         10/26/97
                        1995 A                          8/24/98
================================================================================
</TABLE>

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.

                                       89

<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:

<TABLE>
<CAPTION>

                                                (In thousands of dollars)
--------------------------------------------------------------------------------
1996
--------------------------------------------------------------------------------
                                                    FAIR          CARRYING
                                                    VALUE           AMOUNT
--------------------------------------------------------------------------------
<S>                                             <C>             <C>       
General and Refunding Bonds                     $1,571,745      $1,536,000
Debentures                                       2,271,095       2,270,000
Authority Financing Notes                          950,758         916,675
--------------------------------------------------------------------------------
Total                                           $4,793,598      $4,722,675
================================================================================
1995
--------------------------------------------------------------------------------
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
================================================================================
</TABLE>

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

DEBT MATURITY SCHEDULE

The total  long-term debt maturing in each of the next five years is as follows:
1997, $251 million;  1998, $101 million;  1999, $454 million; 2000, $37 million;
and 2001, $146 million.

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 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 participation in the Primary Plan and compensation.



                                       90

<PAGE>



The Primary Plan's funded status and amounts  recognized on the Balance Sheet at
December 31, 1996 and 1995 were as follows:
<TABLE>
<CAPTION>

                                                       (In thousands of dollars)
--------------------------------------------------------------------------------
                                                               1996         1995
--------------------------------------------------------------------------------
<S>                                                      <C>          <C>
Actuarial present value of benefit obligation
  Vested benefits                                        $ 547,002    $ 518,487
  Nonvested benefits                                        55,157       54,305
--------------------------------------------------------------------------------
Accumulated Benefit Obligation                           $ 602,159    $ 572,792
================================================================================
Plan assets at fair value                                $ 746,400    $ 685,300

Actuarial present value of projected
 benefit obligation                                        689,661      662,360
--------------------------------------------------------------------------------
Projected benefit obligation less
  than plan assets                                          56,739       22,940
Unrecognized net obligation                                 71,085       77,831
Unrecognized net gain                                     (123,759)     (97,285)
--------------------------------------------------------------------------------
Net Prepaid (Accrued) Pension Cost                       $   4,065    $   3,486
================================================================================
</TABLE>

Periodic pension cost for the Primary Plan included the following components:
<TABLE>
<CAPTION>
                                                   (In thousands of dollars)
--------------------------------------------------------------------------------
                                               1996         1995       1994
================================================================================
<S>                                       <C>          <C>          <C>
Service cost - benefits
  earned during the period                $  17,384    $  15,385    $  16,465
Interest cost on projected benefit
  obligation and service cost                47,927       45,987       43,782
Actual return on plan assets                (81,165)    (102,099)     (12,431)
Net Amortization and Deferral                33,541       57,665      (31,633)
--------------------------------------------------------------------------------
Net Periodic Pension Cost                 $  17,687    $  16,938    $  16,183
================================================================================
</TABLE>


Assumptions used in accounting for the Primary Plan were as follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
                                               1996         1995       1994
--------------------------------------------------------------------------------
<S>                                            <C>         <C>        <C>  
Discount rate                                  7.25%       7.25%      7.75%
Rate of future compensation increases          5.00%       5.00%      5.00%
Long-term rate of return on assets             7.50%       7.50%      7.50%
--------------------------------------------------------------------------------
</TABLE>

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

                                       91

<PAGE>



required to recognize  any  deferred net gains or losses over a ten-year  period
rather than using the corridor  approach method.  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  $2.7  million in 1996 and $2.3  million in both 1995 and
1994.

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  $127,000,  $114,000, and $148,000 in
1996, 1995 and 1994, 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.

The PSC  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

                                       92

<PAGE>



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
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,
1996 and 1995, the Company funded the trusts with  approximately $18 million and
$50 million, respectively.

Accumulated postretirement benefit obligation other than pensions at December 31
was as follows:
<TABLE>
<CAPTION>
                                                (In thousands of dollars)
------------------------------------------------------------------------
                                                    1996           1995
------------------------------------------------------------------------
<S>                                            <C>            <C>       
Retirees                                       $  156,181     $  135,497
Fully eligible plan participants                   56,950         52,028
Other active plan participants                    152,627        142,035
------------------------------------------------------------------------
Accumulated postretirement
  benefit obligation                           $  365,758     $  329,560
Plan assets                                        74,692         53,646
------------------------------------------------------------------------
Accumulated postretirement benefit
  obligation in excess of plan assets             291,066        275,914
Unrecognized prior service cost                       188              -
Unrecognized net gain                              75,309        100,335
------------------------------------------------------------------------
Accrued Postretirement Benefit Cost            $  366,187     $  376,249
========================================================================
</TABLE>


At December 31,  1996,  and 1995,  the Plan  assets,  which are recorded at fair
value,  include  cash  and  cash  equivalents,   fixed  income  investments  and
approximately $100,000 of listed equity securities of the Company.

Periodic  postretirement  benefit cost other than pensions for the years were as
follows:
<TABLE>
<CAPTION>
                                                (In thousands of dollars)                          
-------------------------------------------------------------------------
                                      1996           1995            1994
-------------------------------------------------------------------------
<S>                                 <C>           <C>            <C>
Service cost-benefits
   earned during the period         $ 10,690      $  9,082       $ 11,275
Interest cost on projected
   benefit obligation and
   service cost                       25,030        22,412         25,713
Actual return on plan assets          (3,046)       (1,034)             -
Net Amortization
   and Deferral                      (12,175)      (14,699)        (5,213)
--------------------------------------------------------------------------
Periodic Postretirement
   Benefit Cost                     $ 20,499      $ 15,761       $ 31,775
==========================================================================
</TABLE>


                                       93

<PAGE>



Assumptions  used to determine the  postretirement  benefit  obligation  were as
follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
                                                    1996    1995     1994
--------------------------------------------------------------------------------
<S>                                                 <C>     <C>      <C>  
Discount rate                                       7.25%   7.25%    7.75%
Rate of future compensation increases               5.00%   5.00%    5.00%
Long-term rate of return on assets                  7.50%   7.50%     -
--------------------------------------------------------------------------------
</TABLE>


The  assumed  health  care cost trend rates used in  measuring  the  accumulated
postretirement  benefit  obligation  at December 31, 1996 and 1995 were 8.0% and
8.5%,  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, 1996 and 1995
by approximately $43 million and $36 million,  respectively,  and the sum of the
service  and  interest  costs  in 1996 and 1995 by $5  million  and $4  million,
respectively.


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, "Accounting for
Income Taxes", were as follows:
<TABLE>
<CAPTION>

                                                   (In Thousands of dollars)
--------------------------------------------------------------------------------
                                                 1996                   1995
--------------------------------------------------------------------------------
<S>                                      <C>                       <C>
DEFERRED TAX ASSETS
Net operating loss carryforwards         $    145,205              $    338,921
Reserves not currently deductible              58,981                    66,825
Tax depreciable basis in excess
  of book                                      34,314                    41,428
Nondiscretionary excess credits                27,700                    29,826
Credit carryforwards                          135,902                   149,545
Other                                         186,907                   125,246
--------------------------------------------------------------------------------
Total Deferred Tax Assets                $    589,009              $    751,791
--------------------------------------------------------------------------------

DEFERRED TAX LIABILITIES
1989 Settlement                          $  2,163,239              $  2,155,418
Accelerated depreciation                      642,702                   628,475
Call premiums                                  44,846                    50,062
Rate case deferrals                             2,127                    28,971
Other                                          33,496                    35,597
--------------------------------------------------------------------------------
Total Deferred Tax Liabilities              2,886,410                 2,898,523
--------------------------------------------------------------------------------
Net Deferred Tax Liability               $  2,297,401              $  2,146,732
================================================================================
</TABLE>


                                       94

<PAGE>



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:
<TABLE>
<CAPTION>
                                                 (In thousands of dollars)
---------------------------------------------------------------------------
                                                 1996                  1995
---------------------------------------------------------------------------
<S>                                      <C>                   <C>
Regulatory Assets
1989 Settlement                          $  1,660,871          $  1,666,744
Plant items                                   125,976               149,520
Other                                         (14,069)              (13,881)
---------------------------------------------------------------------------
Total Regulatory Assets                  $  1,772,778          $  1,802,383
===========================================================================

Regulatory Liabilities
Carryforward credits                     $     68,421          $     82,330
Other                                          34,466                33,730
---------------------------------------------------------------------------
Total Regulatory Liabilities             $    102,887          $    116,060
===========================================================================
</TABLE>


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.
<TABLE>
<CAPTION>
                                                   (In thousands of dollars)
----------------------------------------------------------------------------
                                            1996          1995          1994
----------------------------------------------------------------------------
<S>                                    <C>           <C>           <C>      
Income before federal income tax       $ 525,721     $ 508,824     $ 478,564
Statutory federal income tax rate            35%           35%           35%
----------------------------------------------------------------------------
Statutory federal income tax           $ 184,002     $ 178,088     $ 167,497

ADDITIONS (REDUCTIONS) IN FEDERAL
  INCOME TAX
  Excess of book depreciation over
    tax depreciation                      18,339        18,588        14,745
  1989 Settlement                          4,212         4,213         4,213
  Interest capitalized                     2,270         2,218         2,449
  Tax credits                             (4,383)       (1,025)       (2,058)
  Tax rate change amortization             3,686         3,752        (4,779)
  Allowance for funds used during
    construction                          (2,305)       (2,392)       (2,450)
  Other items                              3,436         2,096        (2,905)
----------------------------------------------------------------------------
Total Federal Income Tax Expense       $ 209,257     $ 205,538     $ 176,712
============================================================================
Effective Federal Income Tax Rate          39.8%         40.4%         36.9%
============================================================================
</TABLE>


                                       95

<PAGE>



The Company's  net operating  loss (NOL)  carryforwards  for federal  income tax
purposes are  estimated to be  approximately  $415 million at December 31, 1996.
These NOL  carryforwards are scheduled to expire in the years 2004 through 2007.
The  Company  currently  has tax  credit  carryforwards  of  approximately  $136
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  $128  million  and  research  and  development  credits  totaling
approximately $8 million. 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  proposed  ITC  adjustments  which if  sustained,  would  reduce the ITC
carryforwards to approximately $63 million.

Additionally,  the Revenue Agents' Reports reflect  proposed  adjustments to the
Company's  federal income tax returns for the years 1981 through 1989 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 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.  However,  if  necessary,  the Company will avail itself of
interim  financing  via  the  1989  RCA to meet  this  obligation.  The  Company
currently  believes  that a settlement  of the 1981 through 1989 years should be
reached with the Regional Appeals Office sometime in 1997.


NOTE 10. MERGER AGREEMENT WITH THE BROOKLYN UNION GAS COMPANY

On December 29, 1996, the Company and The Brooklyn  Union Gas Company  (Brooklyn
Union)  entered  into  an  Agreement  and  Plan  of  Exchange   (Share  Exchange
Agreement), pursuant to which the companies will be merged in a transaction that
will result in the formation of a new holding company.  The new holding company,
which has not yet been named, will serve approximately 2.2 million customers and
have  revenues  of  more  than  $4.5  billion.  The  merger  is  expected  to be
accomplished  through a  tax-free  exchange  of shares  and  accounted  for as a
pooling of interests.

The proposed  transaction,  which has been approved by both companies' boards of
directors,  would unite the  resources  of the  Company  with the  resources  of
Brooklyn Union. Brooklyn Union, with approximately 3,300 employees,  distributes
natural gas at retail,  primarily  in a territory  of  approximately  187 square
miles  which   includes  the   boroughs  of  Brooklyn  and  Staten   Island  and
approximately  two-thirds  of the  borough  of  Queens,  all in New  York  City.
Brooklyn Union has energy-related investments in gas exploration, production and
marketing in the United States and

                                       96

<PAGE>



Canada, as well as energy services in the United States,  including cogeneration
products, pipeline transportation and gas storage.

Under the terms of the proposed  transaction,  the Company's common  shareowners
will receive .803 shares (the Ratio) of the new holding  company's  common stock
for each share of the Company's common stock that they currently hold.  Brooklyn
Union  common  shareowners  will  receive  one share of common  stock of the new
holding  company  for each  share of  Brooklyn  Union  common  stock  that  they
currently  hold.  Shareowners of the Company will own  approximately  66% of the
common stock of the new holding  company while Brooklyn Union  shareowners  will
own  approximately  34%. The proposed  transaction will have no effect on either
company's debt issues or outstanding preferred stock.

The Share Exchange  Agreement  contains certain covenants of the parties pending
the consummation of the transaction.  Generally, the parties must carry on their
businesses  in the  ordinary  course  consistent  with  past  practice,  may not
increase  dividends on common stock  beyond  specified  levels and may not issue
capital stock beyond certain limits.  The Share Exchange Agreement also contains
restrictions  on, among other  things,  charter and by-law  amendments,  capital
expenditures,  acquisitions,  dispositions,  incurrence of indebtedness, certain
increases in employee  compensation  and benefits,  and affiliate  transactions.
Accordingly,  the  Company's  ability  to engage in certain  activity  described
herein may be limited or prohibited by the Share Exchange Agreement.

Upon completion of the merger,  Dr. William J.  Catacosinos will become chairman
and chief executive  officer of the new holding  company;  Mr. Robert B. Catell,
currently  chairman and chief executive  officer of Brooklyn Union,  will become
president and chief operating officer of the new holding company. One year after
the closing, Mr. Catell will succeed Dr. Catacosinos as chief executive officer,
with Dr. Catacosinos  continuing as chairman.  The board of directors of the new
company will be composed of 15 members,  six from the Company, six from Brooklyn
Union and three additional persons  previously  unaffiliated with either company
and jointly selected by them.

The companies will continue their respective current dividend policies until the
closing,  consistent with the provisions of the Share Exchange Agreement.  It is
expected that the new holding company's dividend policy will be determined prior
to closing.

The merger is conditioned  upon, among other things,  the approval of the merger
by the holders of two-thirds of the  outstanding  shares of common stock of each
of the Company and  Brooklyn  Union and the receipt of all  required  regulatory
approvals.  The Company is unable to determine when or if all required approvals
will be obtained.

In 1995, the Long Island Power Authority  (LIPA),  an agency of the State of New
York (NYS), was requested by the Governor of NYS to develop a plan,  pursuant to
its authority  under NYS law, to provide an electric rate  reduction of at least
10%, provide a framework for long-term

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competition in power production and protect property tax payers on Long Island.

The Share Exchange Agreement contemplates that discussions,  which are currently
in  progress,  will  continue  with  LIPA to  arrive  at an  agreement  mutually
acceptable to the Company, Brooklyn Union and LIPA, pursuant to which LIPA would
acquire certain assets or securities of the Company, the consideration for which
would inure to the benefit of the new holding company.  In the event that such a
transaction  is  completed,  the Ratio would become  .880.  In  connection  with
discussions  with LIPA,  LIPA has  indicated  that it may  exercise its power of
eminent domain over all or a portion of the Company's  assets or securities,  in
order to  achieve  its  objective  of  reducing  current  electric  rates,  if a
negotiated  agreement cannot be reached. The Company is unable to determine when
or if an agreement with LIPA will be reached,  or what action, if any, LIPA will
take if such an agreement is not reached.

NOTE 11. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

ELECTRIC AND GAS

The Company has entered into contracts with numerous Independent Power Producers
(IPPs) and the New York Power Authority (NYPA) for electric generating capacity.
Coincident  with these  agreements are  provisions  which require the Company to
make capacity payments,  fixed non-energy payments and, assuming  performance by
the IPPs and NYPA, payments for energy delivered under these contracts at prices
that may exceed current market energy prices.

The Company has also entered into  contracts  for firm  transmission  (wheeling)
capacity  with  NYPA  in  connection   with  a  transmission   cable  which  was
constructed, in part, for the benefit of the Company.

In  addition,  the  Company has entered  into long term  contracts  for firm gas
transportation,  storage  and supply that  require the Company to make  payments
even if the  services  are not  provided.  

The costs of these agreements are currently recoverable through rates.


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The table  below sets  forth the  Company's  aggregate  obligation  under  these
commitments which extend through 2020.
<TABLE>
<CAPTION>

                                                    (In millions of dollars)
---------------------------------------------------------------------------
                                                   Electric            Gas
                                                   Business*        Business
                                                   ---------        --------
<C>                                               <C>              <C>     
1997                                              $   181.5        $   38.7
1998                                                  188.9            37.6
1999                                                  190.7            37.6
2000                                                  196.5            37.6
2001                                                  205.7            34.7
Subsequent Years                                    2,370.6           232.5
---------------------------------------------------------------------------
Total                                             $ 3,333.9         $ 418.7
Less: Imputed Interest                              1,736.6           182.1
---------------------------------------------------------------------------
Present Value of Payments                         $ 1,597.3         $ 236.6
===========================================================================
</TABLE>

*Assumes full performance by the IPPs and NYPA.

CONTINUOUS EMMISSION MONITORING

The  Company  expended  approximately  $1  million  in 1996  to meet  continuous
emission  monitoring  requirements,  to  meet  Phase  II  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 $44 million by
2003 to meet Phase II and Phase III NOx reduction requirements and approximately
$2 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.

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  1996,  both  the PSC and the  FERC  continued  their
separate,  but in some cases parallel,  initiatives with respect to developing a
framework for a competitive electric marketplace.

THE ELECTRIC INDUSTRY - STATE REGULATORY ISSUES

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

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<PAGE>



electricity while maintaining safe, affordable and reliable service.

As a result of the Competitive Opportunities  Proceedings,  in May 1996, the PSC
issued an order (Order) which stated its belief that introducing  competition to
the electric  industry in New York has the  potential to reduce  electric  rates
over time,  increase  customer choice and encourage  economic growth.  The Order
calls for a  competitive  wholesale  power  market to be in place by early  1997
which will be followed by the introduction of retail access for all customers by
early 1998.

The PSC stated that competition  should be transitioned on an individual company
basis, due to differences in individual service territories,  the level and type
of strandable  investments  (I.E.,  costs that  utilities  would have  otherwise
recovered through rates under traditional cost of service regulation that, under
market  competition,  would not be recoverable) and utility  specific  financial
conditions.

The Order  contemplates  that  implementation of competition will proceed on two
tracks.   The  Order   requires  that  each  major   electric   utility  file  a
rate/restructuring plan which is consistent with the PSC's policy and vision for
increased  competition.  Those  plans were  submitted  by  October  1, 1996,  in
compliance  with  the  Order.  However,  the  Company  was  exempted  from  this
requirement due to the PSC's separate  investigation  of the Company's rates and
LIPA's  examination  of  the  Company's   structure.   Since  October  1,  1996,
proceedings  have  commenced  for  the  five  electric   utilities  which  filed
restructuring  plans in accordance with track one and the Company has intervened
in each of these proceedings.

The PSC order also  anticipated  that  certain  other  filings  would be made on
October 1, 1996, by all New York State utilities,  to both the PSC and the FERC.
The filings were to address the  delineation of  transmission  and  distribution
facilities jurisdiction between the FERC or the PSC, a pricing of each company's
transmission  services,  and a joint filing by all the  utilities to address the
formation of an Independent  System  Operator (ISO) and the creation of a market
exchange that will establish  spot market prices.  Although there were extensive
collaborative meetings among the parties, it was not possible for the additional
filings  to be  completed  by  October  1, 1996.  While  these  discussions  are
continuing  in an  attempt  to narrow  the  differences  among the  parties,  on
December 31, 1996, the New York Power Pool (NYPP) members submitted a compliance
filing to the FERC which provides open  membership  and  comparable  services to
eligible  entities in accordance  with FERC Order 888,  discussed  below.  It is
anticipated  that the New York State  utilities  will submit the full  ISO/Power
Exchange filing to the FERC during the first quarter of 1997.

The PSC envisions that a fully operational  wholesale competitive structure will
foster the expeditious movement to full retail competition.  The PSC's vision of
the retail  competitive  structure,  known as the Flexible  Retail Poolco Model,
consists  of: (i) the  creation of an ISO to  coordinate  the safe and  reliable
operation  of  electric  generation  and  transmission;  (ii) open access to the
transmission   system,   which  would  be  regulated  by  the  FERC;  (iii)  the
continuation of a regulated

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<PAGE>



distribution  company to operate and maintain the distribution  system; (iv) the
deregulation  of  energy/customer  services  such as meter  reading and customer
billing;  (v) the ability of customers to choose among suppliers of electricity;
and (vi) the allowance of customers to acquire  electricity  either by long-term
contracts, purchases on the spot market or a combination of the two.

One issue  discussed  in the Order that could  affect the Company is  strandable
investments.  The PSC  stated  in its  Order  that it is not  required  to allow
recovery  of all  prudently  incurred  investments,  that  it  has  considerable
discretion to set rates that balance  ratepayer and shareholder  interests,  and
that the amount of  strandable  investments  that a utility will be permitted to
recover  will  depend  on  the   particular   circumstances   of  each  utility.
Additionally,  the Order  provided that every effort should be made by utilities
to mitigate these costs prior to seeking recovery.

Certain aspects of the  restructuring  envisioned by the  PSC--particularly  the
PSC's apparent determinations that it may deny the utilities recovery of prudent
investments  made on  behalf  of the  public,  order  retail  wheeling,  require
divestiture of generation  assets and deregulate  certain  sectors of the energy
market--could,  if  implemented,  have a negative  impact on the  operations and
financial conditions of New York's investor-owned electric utilities,  including
the Company.

The  Company is party to a lawsuit  commenced  in  September  1996 by the Energy
Association  of New York State and the  state's  other  investor-owned  electric
utilities (collectively, Petitioners) against the PSC in New York Supreme Court,
Albany  County  (The  Energy  Association  of New York  State,  et al. v. Public
Service  Commission  of the State of New York,  et al.).  The  Petitioners  have
requested  that  the  Court  declare  that  the  Order is  unlawful  or,  in the
alternative,  that the  Court  clarify  that the PSC's  statements  in the Order
constitute  simply a policy statement with no binding legal effect.  In November
1996, the Court issued a Decision and Order denying the Petitioners'  request to
invalidate  the Order.  Although  the Court  stated  that most of the Order is a
non-binding statement of policy, the Court rejected the Petitioners' substantive
challenges to the Order. In December 1996,  Petitioners filed a notice of appeal
with the  Third  Department  of the  Appellate  Division  of the New York  State
Supreme Court.  The litigation is ongoing and the Company is unable at this time
to predict  the  likelihood  of success or the impact of the  litigation  on the
Company's financial position, cash flows or results of operations. Oral argument
in the Appellate Division has not yet been scheduled, but a decision is expected
by the end of 1997.

THE ELECTRIC INDUSTRY - FEDERAL REGULATORY ISSUES

In April 1996, in response to its Notice of Proposed  Rulemaking issued in March
1995,  the FERC issued two orders  relating to the  development  of  competitive
wholesale electric markets.

Order 888 is a final rule on open transmission access and stranded cost

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recovery and provides that the FERC has exclusive  jurisdiction  over interstate
wholesale  wheeling  and that utility  transmission  systems must now be open to
qualifying sellers and purchasers of power on a non-discriminatory basis.

Order 888  allows  utilities  to  recover  legitimate,  prudent  and  verifiable
stranded   costs   associated   with  wholesale   transmission,   including  the
circumstances  where full requirements  customers become wholesale  transmission
customers, such as where a municipality establishes its own electric system.

With respect to retail  wheeling,  the FERC concluded  that it has  jurisdiction
over  rates,  terms and  conditions  of  service,  but would  leave the issue of
recovery of the costs stranded by retail wheeling to the states.

Order 888 required  utilities to file open access tariffs under which they would
provide transmission services, comparable to those which they provide themselves
and to third parties on a non-discriminatory basis. Additionally, utilities must
use these same tariffs for their own wholesale sales. The Company filed its open
access tariff in July 1996.

In September  1996,  the FERC ordered Rate  Hearings on 28 utility  transmission
tariffs, including the Company's. On the basis of a preliminary review, the FERC
was not  satisfied  that the tariff rates were just and  reasonable.  Settlement
discussions  have  been  held  between  the  Company  and  various   intervenors
concerning  the Company's  transmission  rates.  In December  1996,  the parties
reached a tentative  settlement on the rate issues. The procedural  schedule was
suspended  pending  filing of the  settlement  agreement,  which is  anticipated
during the first quarter of 1997.  Non-rate issues associated with the Company's
open access tariff have not yet been addressed by the FERC.

Order  889,  which is a final rule on a  transmission  pricing  bulletin  board,
addresses  the rules and  technical  standards  for  operation of an  electronic
bulletin  board  that will make  available,  on a  real-time  basis,  the price,
availability  and  other  pertinent  information  concerning  each  transmission
utility's  services.  It also  addresses  standards  of conduct  to ensure  that
transmission  utilities  functionally  separate their transmission and wholesale
power merchant  functions to prevent  discriminatory  self-dealing.  In December
1996, the Company filed its standards of conduct in accordance with the Order.

With other  members of the  industry,  the Company has  participated  in several
joint petitions for rehearing and/or  clarification of the FERC's Orders 888 and
889.  Among other  issues,  these  petitions  address the FERC's  obligation  to
exercise its jurisdiction to provide for the recovery of strandable  investments
in any retail wheeling situations.  The outcome and timing of the FERC Orders on
rehearing are uncertain.

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


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Company would recover in a competitive environment. The outcome of the state and
federal  regulatory  proceedings could adversely affect the Company's ability to
apply 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," could then require a significant write-down of all or a portion
of the Company's net regulatory assets.

THE COMPANY'S SERVICE TERRITORY

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.  However,  the  changing  utility
regulatory  environment  has affected  the Company by  requiring  the Company to
co-exist with state and federally  mandated  competitors.  These competitors are
non-utility generators (NUGS), NYPA and Municipal Distribution Agencies (MDAs).

The Public Utility Regulatory Policies Act of 1978 (PURPA), the goal of which is
to reduce the United  States'  dependency  on foreign oil, to  encourage  energy
conservation and to promote  diversification  of the fuel supply, has negatively
impacted  the  Company  through the  encouragement  of the NUG  industry.  PURPA
provides for the development of a new class of electric generators which rely on
either cogeneration technology or alternate fuels. Utilities are obligated under
PURPA to purchase the output of certain of these generators,  which are known as
qualified facilities (QFs).

In 1996,  the  Company  lost sales to NUGs  totaling  422  gigawatt-hours  (GWh)
representing  a  loss  in  electric  revenues  net of  fuel  (net  revenues)  of
approximately $34 million,  or 1.9% of the Company's net revenues.  In 1995, the
Company lost sales to NUGs totaling 366 GWh or approximately $28 million or 1.5%
of the Company's net revenues.

The increase in lost net revenues  resulted  principally  from the completion of
seven facilities that became  commercially  operational during 1996 and the full
year  operation of the IPP located at the State  University of New York at Stony
Brook, NY. The Company  estimates that in 1997, sales losses to NUGs will be 429
GWh, or approximately 1.8% 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 1996  approximated 218 megawatts (MW) and in early
1995  approximated  205 MW. The  increase was the result of the SUNY Stony Brook
facility going on line in mid 1995. The Company


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<PAGE>



estimates  that  purchases  from QFs  required by federal and state law cost the
Company $63 million and $53 million in 1996 and 1995, respectively, more than it
would have cost had the Company generated this power.

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  continues to apply 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 within its service territory.

The Company  has also  experienced  a revenue  loss as a result of its policy of
voluntarily  providing  wheeling  of NYPA power for  economic  development.  The
Company  estimates that in 1996 and 1995 NYPA power displaced  approximately 417
GWh  and  429  GWh of  annual  energy  sales,  respectively.  Net  revenue  loss
associated with these volumes of sales is approximately $26 million,  or 1.4% of
the Company's 1996 net revenues,  and $30 million, or 1.6% of the Company's 1995
net revenues.  Currently,  the potential  loss of additional  load is limited by
conditions in the Company's transmission agreements with NYPA.

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 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 that is likely to increase as a result
of the  National  Energy  Policy Act of 1992  (NEPA).  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. NEPA does so by creating exempt wholesale generators that can sell power
in  wholesale  markets  without  the  regulatory  constraint  placed on  utility
generators  such as on the Company.  NEPA also expanded the FERC's  authority to
grant access to utility  transmission  systems to all parties who seek wholesale
wheeling  for  wholesale  competition.  While it should be noted that the FERC's
position favoring stranded cost recovery from retail turned wholesale  customers
will reduce utility risk from  municipalization,  significant  issues associated
with the removal of  restrictions on wholesale  transmission  system access have
yet to be resolved.

There are numerous towns and villages in the Company's service territory


                                      104

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that are considering the formation of a municipally  owned and operated electric
authority to replace the services currently provided by the Company.

In 1995,  Suffolk  County issued a request for proposal from suppliers for up to
300 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.  After the Company
challenged Suffolk County's  eligibility for such service, the County petitioned
the FERC to order the Company to provide the requested transmission service.

In December 1996, the FERC ordered the Company to provide transmission  services
to Suffolk  County to the extent  necessary  to  accommodate  proposed  sales to
customers  to which it was  providing  service on the date of  enactment of NEPA
(this Order could provide Suffolk County with the ability to import up to 200 MW
of power on a daily basis).  The FERC reserved  decision on the remaining 100 MW
of Suffolk County's request until the County identifies the ownership or control
of distribution  facilities that it alleges qualifies it for a wheeling order to
Suffolk  County  customers who were not receiving  service on the date of NEPA's
enactment.  The Company may ask the FERC to reconsider  their decision once that
decision becomes final,  which is not expected for several months.  The FERC has
yet to determine the pricing of that service.  As previously  noted,  FERC order
888 allows  utilities to recover  legitimate,  prudent and  verifiable  stranded
costs associated with wholesale transmission,  including the circumstances where
full requirements  customers become wholesale  transmission  customers,  such as
where a municipality establishes its own electric 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 the FERC may take regarding any of these matters,  or the impact
on the Company's financial position, cash flows or results of operations 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  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.

ENVIRONMENTAL MATTERS

The Company is subject to federal,  state and local laws and regulations dealing
with air and  water  quality  and  other  environmental  matters.  Environmental
matters may expose the Company to potential liabilities



                                      105

<PAGE>



which,  in  certain  instances,  may be imposed  without  regard to fault or for
historical  activities which were lawful at the time they occurred.  The Company
continually  monitors its  activities  in order to  determine  the impact of its
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  (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 are believed to have produced manufactured
gas. 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.  Research is
underway  to  determine  the  existence  and  nature  of  operations  and  their
relationship, if any, to the Company or its predecessor companies.

The  Company  has entered  into  discussions  with the DEC which may lead to the
issuance  of one or more  Administrative  Consent  Orders  (ACO)  regarding  the
management of environmental  activities at these properties.  Although the exact
amount of the Company's remediation costs cannot yet be determined, based on the
findings of investigations at two of these six sites, estimates indicate that it
will cost  approximately $51 million to remediate all of these sites through the
year 2005.  Accordingly,  the Company has 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 $35 million  liability  reflects the present value of
the future  stream of payments to  investigate  and remediate  these sites.  The
Company used a risk-free rate of 7.25% to discount this obligation.

In December  1996,  the Company filed a complaint in the United States  District
Court for the Southern District of New York against 14 of the Company's insurers
which issued general comprehensive  liability (GCL) policies to the Company. The
Company is seeking  recovery  under the GCL policies  for the costs  incurred to
date and future costs  associated with the clean-up of the Company's  former MGP
sites and  Superfund  sites for which the Company  has been named a  potentially
responsible party (PRP). The Company is seeking a declaratory  judgment that the
defendant  insurers are bound by the terms of the GCL  policies,  subject to the
stated coverage limits, to reimburse the Company for the remediation  costs. The
outcome of this proceeding cannot yet be determined.

The Company  has been  notified by the United  States  Environmental  Protection
Agency (EPA) that it is one of many 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.

                                      106


<PAGE>



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),  which has been  completed  and is currently  being
reviewed  by the  EPA.  Under a PRP  participation  agreement,  the  Company  is
responsible  for 8.2% of the  costs  associated  with this  RI/FS.  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  cost to  remediate  this  site  based  upon  its  8.2%
responsibility under the RI/FS.

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 company named 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 and certain soil areas outside the buildings are contaminated with
PCBs.

In 1994,  the EPA requested  certain of the large PRPs,  which  include  several
other utilities, to form a group, sign an ACO, and conduct a remediation program
for the sites under the Toxic Substances Control Act, or in the alternative,  to
perform a Superfund cleanup for the sites. The EPA has 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 Company  intends to join a PRP
Group which includes other  utilities,  which has been organized for the purpose
of developing and implementing  acceptable  remediation  programs for the sites.
The Company is currently  unable to determine its share of the cost to remediate
these sites.

In  addition,  the Company  was  notified  that it is a PRP at a Superfund  site
located  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 remediation  expenses in the amount
of approximately $100,000 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 costs of remediation at this site.

During 1996, the Connecticut Department of Environmental Protection (DEP) issued
a modification to an ACO previously  issued in connection with an  investigation
of an electric  transmission  cable  located  under the Long Island Sound (Sound
Cable) that is jointly owned by the Company and the Connecticut  Light and Power
Company (Owners).  The modified ACO requires the Owners to submit to the DEP and
DEC a series of reports and studies describing cable system condition, operation
and repair  practices,  alternatives  for cable  improvements or replacement and
environmental impacts associated with leaks of fluid into the Long Island Sound,
which have occurred from time to time. The Company continues to compile


                                      107


<PAGE>


required  information  and coordinate the activities  necessary to perform these
studies and, at the present time, is unable to determine the costs it will incur
to  complete  the  requirements  of the  modified  ACO  or to  comply  with  any
additional requirements.

Previously,  the U.S.  Attorney for the District of Connecticut had commenced an
investigation  regarding  occasional  releases of fluid from the Sound Cable, as
well as associated operating and maintenance practices. The Owners have provided
the U.S.  Attorney with all requested  documentation.  The Company believes that
all  activities  associated  with the response to  occasional  releases from the
Sound Cable were consistent with legal and regulatory requirements.

In  addition,  during  1996 the  Long  Island  Soundkeeper  Fund,  a  non-profit
organization,  filed a suit  against  the  Owners of the Sound  Cable in Federal
District  Court  in  Connecticut  alleging  that the  Sound  Cable  fluid  leaks
constitute  unpermitted discharges of pollutants in violation of the Clean Water
Act (CWA)  and that such  pollutants  present  a threat to the  environment  and
public health. The suit seeks, among other things, injunctive relief prohibiting
the Owners from  continuing  to operate the Sound Cable in alleged  violation of
the CWA and civil  penalties of $25,000 per day for each  violation from each of
the Owners.

In December 1996, a barge, owned and operated by a third party,  dropped anchor,
causing  extensive  damage to the Sound Cable and a release of dielectric  fluid
into the Long Island Sound.  Temporary  clamps and leak abaters have been placed
on the cables and have stopped the leaks.  Permanent  repairs are expected to be
undertaken in the late spring of 1997. The  preliminary  estimate of the cost of
these  repairs is $15 million.  The Company  intends to seek recovery from third
parties  for costs  incurred by the  Company as a result of this  incident.  The
timing and amount of recovery,  if any,  cannot yet be determined.  In addition,
the Owners  maintain  insurance  coverage  for the Sound Cable which the Company
believes will be sufficient to cover any repair costs.  In any event,  costs not
reimbursed by a third party or not covered by insurance  will be shared  equally
by the Owners.

The Company believes that none of the  environmental  matters,  discussed above,
will have a material adverse impact on the Company's  financial  position,  cash
flows or results of  operations.  In  addition,  the Company  believes  that all
significant  costs  incurred  with respect to  environmental  investigation  and
remediation  activities,  not  recoverable  from  insurance  carriers,  will  be
recoverable through rates.



                                       108

<PAGE>



NOTE 12. 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, common net utility
plant and unamortized cost of issuing securities.
<TABLE>
<CAPTION>

                                            (In millions of dollars)
----------------------------------------------------------------------
For year ended December 31              1996         1995         1994
----------------------------------------------------------------------
<S>                                  <C>         <C>          <C>
OPERATING REVENUES
Electric                             $  2,467    $  2,484     $  2,481
Gas                                       684         591          586
----------------------------------------------------------------------
Total                                $  3,151    $  3,075     $  3,067
======================================================================
OPERATING EXPENSES 
  (excludes federal income tax)
Electric                             $  1,644    $  1,657     $  1,640
Gas                                       560         478          500
----------------------------------------------------------------------
Total                                $  2,204    $  2,135     $  2,140
======================================================================
OPERATING INCOME 
  (before federal income tax)
Electric                             $    823    $    827     $    842
Gas                                       124         113           85
----------------------------------------------------------------------
Total operating income                    947         940          927
AFC                                       (6)         (7)          (7)
Other income and deductions              (23)        (38)         (45)
Interest charges                          451         476          500
Federal income tax                        209         206          177
----------------------------------------------------------------------
Net Income                           $    316    $    303     $    302
======================================================================

DEPRECIATION AND AMORTIZATION
Electric                             $    129    $    122     $    112
Gas                                        25          23           19
----------------------------------------------------------------------
Total                                $    154    $    145     $    131
======================================================================

CONSTRUCTION AND NUCLEAR 
  FUEL EXPENDITURES*
Electric                             $    165    $    162     $    155
Gas                                        78          84          125
----------------------------------------------------------------------
Total                                $    243    $    246     $    280
======================================================================
</TABLE>

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

<TABLE>
<CAPTION>
                                            (In millions of dollars)
----------------------------------------------------------------------
At December 31                           1996        1995         1994
----------------------------------------------------------------------
<S>                                  <C>         <C>          <C>
IDENTIFIABLE ASSETS
Electric                             $  9,835    $ 10,020     $ 10,285
Gas                                     1,232       1,181        1,181
----------------------------------------------------------------------
Total identifiable assets              11,067      11,201       11,466
Assets utilized for overall
 Company operations                     1,143       1,326        1,013
----------------------------------------------------------------------
Total Assets                         $ 12,210    $ 12,527     $ 12,479
======================================================================
</TABLE>


                                       109

<PAGE>




NOTE 13. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
<TABLE>
<CAPTION>
                  (In thousands of dollars except earnings per common share)
--------------------------------------------------------------------------------
                                                          1996           1995
--------------------------------------------------------------------------------
<S>                                                <C>            <C>
Operating revenues
      For the quarter ended March 31               $   864,214    $    791,188
                             June 30                   694,602         653,824
                        September 30                   849,775         875,794
                         December 31                   742,104         754,322
================================================================================
Operating income
      For the quarter ended March 31               $   190,421    $    180,875
                             June 30                   141,065         143,246
                        September 30                   235,402         239,561
                         December 31                   169,693         167,936
================================================================================
Net income
      For the quarter ended March 31               $    81,753    $     70,299
                             June 30                    40,524          41,392
                        September 30                   130,023         131,221
                         December 31                    64,164          60,374
================================================================================
Earnings for common stock
      For the quarter ended March 31               $    68,682    $     57,127
                             June 30                    27,453          28,220
                        September 30                   116,972         118,069
                         December 31                    51,141          47,250
================================================================================
Earnings per common share
      For the quarter ended March 31               $       .57    $        .48
                             June 30                       .23             .24
                        September 30                       .97             .99
                         December 31                       .43             .39
================================================================================
</TABLE>

                                       110

<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, 1996 and 1995 and
the related  statements of income,  retained earnings and cash flows for each of
the three years in the period ended  December 31, 1996. 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, 1996 and 1995, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1996, 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
January 31, 1997

                                             /S/ Ernst & Young LLP
                                             ---------------------
                                               Ernst & Young LLP
                                       111

<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 definitive proxy statement between the Company and
The Brooklyn Union Gas Company  (definitive  proxy) for its annual meeting to be
held on May 8,  1997  (Annual  Meeting).  Such  definitive  proxy  statement  is
incorporated herein by reference.

ITEM 11.  EXECUTIVE COMPENSATION

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


                                       112

<PAGE>



                                     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, 1996.

        Balance Sheet at December 31, 1996 and 1995.

        Statement of Retained Earnings for each of the three years in the period
          ended December 31, 1996.

        Statement of Capitalization at December 31, 1996 and 1995.

        Statement of Cash Flows for each of the three years in the period  ended
          December 31, 1996.

        Notes to Financial Statements.

   (2)    LIST OF FINANCIAL STATEMENT SCHEDULES

        Valuation and Qualifying Accounts (Schedule II)



                                       113

<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.)

*3(b)  By-laws of the Company as amended on December 18, 1996.

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

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).

--------------------
*Filed herewith.

                                       114

<PAGE>



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).

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).

                                       115

<PAGE>




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) and as amended by  Amendment  No. 3 And
Waiver to the Credit Agreement dated as of July 19, 1996.

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).

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).

---------------------
*Filed herewith.

                                       116

<PAGE>




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 (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31, 1995).

Participation  Agreement  dated as of August 1, 1995 by and between  NYSERDA and
the Company  relating  to the 1995  EFRBs,  Series A (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1995).

10(y)  Supplemental  Death and Retirement  Benefits Plan as amended and restated
effective  January 1, 1993 (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

                                       117

<PAGE>



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)
Charles A. Daverio dated as of December 1, 1996, (2) James T. Flynn,  (3) Joseph
E.  Fontana,  (4) Robert X.  Kelleher,  (5) John D.  Leonard,  Jr.,  (6) Adam M.
Madsen, (7) Kathleen A. Marion, (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) Werner J. Schweiger dated
as of December  1, 1996,  (15)  Richard M. Siegel  dated as of December 1, 1996,
(16) Robert B. Steger, (17) William E. Steiger, and (18) 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) Charles A.
Daverio  dated as of December  1, 1996,  (2) James T. Flynn dated as of November
25,  1987,  (3) Joseph E. Fontana  dated as of October 20,  1994,  (4) Robert X.
Kelleher  dated as of November 25, 1987,  (5) John D.  Leonard,  Jr. dated as of
November  25,  1987,  (6) Adam M. Madsen  dated as of  November  25,  1987,  (7)
Kathleen A. Marion dated as of May 30, 1990, (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) Werner J.  Schweiger
dated as of December  1, 1996,  (15)  Richard M. Siegel  dated as of December 1,
1996,  (16) Robert B. Steger  dated as of February  20,  1990,  (17)  William E.
Steiger, Jr. dated as of March 1, 1989, and (18) 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,  and (10) John H.
Talmage 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.

 (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).


                                       118

<PAGE>


     *(9)  Consulting  Agreement  dated  as of May 9,  1996 by and  between  the
Company and Lionel M. Goldberg,  which  agreement is  substantially  the same as
Consulting Agreement dated as of May 9, 1996 by and between the Company and Eben
W. Pyne.

10(aa)  Agreement  and Plan of Exchange,  dated as of December  29, 1996,  among
NYECO Corp.,  The Brooklyn Union Gas Company and Long Island  Lighting  Company,
(filed as Exhibit to the Company's Current Report on Form 8-K dated December 30,
1996).

10(bb) LILCO Stock Option Agreement,  dated as of December 29, 1996, between The
Brooklyn Union Gas Company and Long Island Lighting Company (filed as an Exhibit
to the Company's Schedule 13D dated January 9, 1997).

10(cc) BUG Stock Option  Agreement,  dated as of December 29, 1996,  between The
Brooklyn Union Gas Company and Long Island Lighting Company (filed as an Exhibit
to the Company's Schedule 13D dated January 9, 1997).

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

*24(a) Powers of Attorney executed by the Directors and Officers of the Company.

*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

In its Current Report on Form 8-K dated December 30, 1996, the Company  reported
that it and The Brooklyn Union Gas Company entered into an agreement and plan of
exchange to merge in a tax-free transaction.



--------
*Filed herewith.

                                       119

<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
                                       beginning       costs and   accounts-    Deductions-       end of
Description                            of period       expenses    describe     describe          period
--------------------------------------------------------------------------------------------------------
<S>                                    <C>              <C>           <C>        <C>             <C>   
Year ended December 31, 1996 
Deducted from asset accounts:
Allowance for doubtful accounts        $24,676          $23,119       --         $22,795 (1)     $25,000

Year ended December 31, 1995
Deducted from asset accounts:
Allowance for doubtful accounts        $23,365          $17,751       --         $16,440 (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

</TABLE>

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


                                       120

<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 and Chairman
                      of the Board of Directors

                      JAMES T. FLYNN*
                      ---------------
                      James T. Flynn, President,
                      Chief Operating Officer,
                      Director

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

                      A. JAMES BARNES*
                      ----------------
                      A. James Barnes, Director

                      GEORGE BUGLIARELLO*
                      -------------------
                      George Bugliarello, Director
February 6, 1997
                      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

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

                                       121

<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.

Date:  February 6, 1997


                              LONG ISLAND LIGHTING COMPANY

                              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.



                                       122

<PAGE>