S E C U R I T I E S   A N D   E X C H A N G E   C O M M I S S I O N
                             WASHINGTON, D.C. 20549


                                      FORM 10-K                              
[X]             ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE         
                  SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]          
                      FOR THE FISCAL YEAR ENDED MARCH 31, 1998               
                                         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)

<TABLE>
<CAPTION>

Preferred Stock ($100 par, cumulative):
<S>                                     <C>                                <C> 
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:
    7.85% Series Due 1999              8.50% Series Due 2006               9 3/4% Series Due 2021
   8 5/8% Series Due 2004              7.90% Series Due 2008               9 5/8% Series Due 2024

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

         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 March 31,1998 was  $3,832,943,909.  The aggregate market value
of  Preferred  Stock held by  non-affiliates  of the Company at March 31,  1998,
established  by Lehman  Brothers  based on the average bid and asked price,  was
$735,033,360.

    COMMON STOCK ($5 PAR) - SHARES OUTSTANDING AT MARCH 31, 1998: 121,680,759


<PAGE>

<TABLE>
<CAPTION>

                                TABLE OF CONTENTS


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

                                     PART I

<S>          <C>                                                                                                  <C>
ITEM 1.      BUSINESS...............................................................................................1
             The Company............................................................................................1
             Territory..............................................................................................1
             Business Segments......................................................................................1
             Employees..............................................................................................1
             Regulation and Accounting Controls.....................................................................2
             Long Island Power Authority Transaction................................................................2
             KeySpan Energy Corporation Transaction.................................................................4
             Competitive Environment................................................................................6
             Electric Operations....................................................................................6
                      General.......................................................................................6
                      System Requirements, Energy Available and Reliability.........................................7
                      Energy Sources................................................................................7
                              Oil...................................................................................7
                              Natural Gas...........................................................................8
                              Purchased Power.......................................................................8
                              Nuclear...............................................................................9
                              Interconnections......................................................................9
                      Conservation Services.........................................................................9
                      The 1989 Settlement...........................................................................9
                      Electric Rates................................................................................9
             Gas Operations........................................................................................10
                      General......................................................................................10
                      Gas System Requirements......................................................................10
                              Peak Day Capability..................................................................11
                              Transportation ......................................................................11
                              Storage..............................................................................11
                              Cogen/IPP Deliveries.................................................................11
                              Peak Shaving.........................................................................11
                              Firm Gas Supply......................................................................12
                      Gas Rates....................................................................................12
                      Recovery of Transition Costs.................................................................12
                      Natural Gas Vehicles.........................................................................12
             Environmental Matters.................................................................................12
                      General......................................................................................12
                      Air..........................................................................................13
                      Water........................................................................................15
                      Land.........................................................................................16
                      Nuclear Waste................................................................................19
             The Company's Securities..............................................................................20
                      General......................................................................................20
                      The G&R Mortgage.............................................................................20
                      Unsecured Debt...............................................................................21
                      Equity Securities............................................................................21
                              Common Stock.........................................................................21
                              Preferred Stock......................................................................22
                              Preference Stock.....................................................................22
             Executive Officers of the Company.....................................................................23
             Capital Requirements, Liquidity and Capital Provided..................................................28

ITEM 2.      PROPERTIES............................................................................................28

ITEM 3.      LEGAL PROCEEDINGS.....................................................................................28
             Shoreham..............................................................................................28
             Environmental.........................................................................................29
             Human Resources.......................................................................................30
             Other Matters.........................................................................................30

ITEM 4.      SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...................................................30
</TABLE>

                                       i

<PAGE>

<TABLE>
<CAPTION>

                                     PART II
<S>          <C>                                                                                                        <C>
ITEM 5.      MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTER...................................31

ITEM 6.      SELECTED FINANCIAL DATA....................................................................................32

ITEM 7.      MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS......................33

ITEM 8.      FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................................................55
             Balance Sheet..............................................................................................55
             Statement of Income........................................................................................57
             Statement of Cash Flows....................................................................................58
             Statement of Retained Earnings.............................................................................59
             Statement of Capitalization................................................................................59
             Notes to Financial Statements..............................................................................61
             Report of Independent Auditors.............................................................................96

ITEM 9.      CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
             AND FINANCIAL DISCLOSURES..................................................................................97

                              PART III

ITEM 10.     DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY............................................................98

ITEM 11.     EXECUTIVE COMPENSATION....................................................................................101
ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............................................113

ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................................................116

                               PART IV

ITEM 14.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
             FORM 8-K..................................................................................................117
                      List of Financial Statements.....................................................................117
                      List of Financial Statement Schedules............................................................117
                      List of Exhibits.................................................................................118
                      Reports  on  Form  8-K...........................................................................129
                      SCHEDULE II .....................................................................................130

SIGNATURES.............................................................................................................131
</TABLE>


<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)
MWh..................  Megawatt Hour
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
PACB.................  Public Authorities Control Board
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


<PAGE>

                                     PART I

ITEM 1.  BUSINESS
THE COMPANY
Long Island Lighting  Company  (Company or LILCO) 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.

On April 11, 1997,  the Company  changed its year end from  December 31 to March
31.  Accordingly,  unless  otherwise  indicated,  references  to 1998  and  1997
represent  the twelve  month  periods  ended March 31, 1998 and March 31,  1997,
respectively,  while  references to all other  periods  refer to the  respective
calendar years ended December 31.

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 1998 Long
Island  Population  Survey,  is 2.75 million  persons,  including  approximately
98,500 persons who reside in Queens County within the City of New York. The 1998
population survey reflects a 1.6% increase since the 1990 census.

Approximately  80% of all workers  residing in Nassau and Suffolk  Counties  are
employed within the two counties.  During the year ended December 31, 1997 total
non-agricultural   employment  in  Nassau  and  Suffolk  Counties  increased  by
approximately 18,600 positions, an employment increase of 1.7%.

The Company  serves  approximately  1.04  million  electric  customers  of which
approximately 931,000 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  467,000 gas customers,  417,000 of which
are residential,  accounting for about 61% of its gas revenues,  17,000 of which
are  commercial/industrial,  accounting  for 23% of its gas  revenues,  3,600 of
which are firm transportation customers,  accounting for 3% of its gas revenues,
with the balance of the gas revenues derived from off-system sales.

BUSINESS SEGMENTS
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" and Note 13 of Notes to Financial
Statements.

EMPLOYEES
As of March 31, 1998, the Company had 5,187 full-time employees,  of which 2,149
belong  to Local  1049 and  1,220  belong  to  Local  1381 of the  International
Brotherhood of Electrical Workers.  Effective February 14, 1996, the Company and
these unions agreed upon  contracts  which will expire on February 13, 2001. The
contracts  provide,  among other things,  for wage increases totaling 15.5% over
the term of the agreements.

                                       1

<PAGE>

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.

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 Note 12 of Notes to Financial  Statements.
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).

LONG ISLAND POWER AUTHORITY TRANSACTION
On June 26, 1997,  the Company and Long Island Power  Authority  (LIPA)  entered
into  definitive  agreements  pursuant  to  which,  after  the  transfer  of the
Company's gas business unit assets,  non-nuclear  electric  generating  facility
assets and certain  other  assets and  liabilities  to one or more  newly-formed
subsidiaries  of a new holding company  (HoldCo),  formed in connection with the
LIPA Transaction and KeySpan  Transaction  discussed below, the Company's common
stock will be sold to LIPA for $2.4975 billion in cash.

In connection with this transaction, the principal assets to be acquired by LIPA
through  its  stock  acquisition  of LILCO  include:  (i) the net book  value of
LILCO's  electric  transmission  and  distribution  system,  which  amounted  to
approximately  $1.3 billion at March 31, 1998;  (ii) LILCO's net  investment  in
NMP2,  which  amounted to  approximately  $0.7 billion at March 31, 1998;  (iii)
certain of LILCO's regulatory assets associated with its electric business;  and
(iv) allocated accounts receivable and other assets. The regulatory assets to be
acquired by LIPA amounted to  approximately  $6.6 billion at March 31, 1998, and
primarily  consist  of the  Base  Financial  Component  (BFC),  Rate  Moderation
Component (RMC), Shoreham  post-settlement costs, Shoreham nuclear fuel, and the
electric portion of the regulatory tax asset. For a further  discussion of these
regulatory assets, see Note 1 of Notes to Financial Statements.

LIPA is  contractually  responsible  for reimbursing  HoldCo for  postretirement
benefits  other than pension  costs  related to  employees  of LILCO's  electric
business.  Accordingly,  upon  consummation  of  the  transaction,  HoldCo  will
reclassify the associated  regulatory  asset for  postretirement  benefits other
than pensions to a contractual receivable.

The principal liabilities to be assumed by LIPA through its stock acquisition of
LILCO include: 


                                        2

<PAGE>

(i) LILCO's regulatory liabilities  associated with its electric business;  (ii)
allocated accounts payable, customer deposits, other deferred credits and claims
and damages; and (iii) certain series of long-term debt, a portion of which will
be  refinanced.  The  regulatory  liabilities  to be assumed by LIPA amounted to
approximately  $365  million at March 31,  1998,  and  primarily  consist of the
regulatory liability component, 1989 Settlement credits and the electric portion
of the regulatory tax liability.  For a further  discussion of these  regulatory
liabilities, see Note 1 of Notes to Financial Statements.

The  long-term  debt to be assumed by LIPA will consist of: (i) all amounts then
outstanding under the General and Refunding (G&R)  Indentures;  (ii) all amounts
then  outstanding  under the Debenture  Indentures,  except as noted below;  and
(iii)  substantially all of the tax-exempt  authority financing notes. HoldCo is
required to assume the financial obligation associated with the 7.30% Debentures
due July 15, 1999, with an aggregate  principal amount currently  outstanding of
$397  million  and  8.20%  Debentures  due  March 15,  2023,  with an  aggregate
principal  amount  currently  outstanding  of $270 million.  HoldCo will seek to
exchange  its  Debentures,  with  identical  terms,  for  these  two  series  of
Debentures  and will issue a  promissory  note to LIPA in an amount equal to the
unexchanged amount of such Debentures.  HoldCo will also issue a promissory note
to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current
gas operations, with terms identical to those currently outstanding. The Company
currently  estimates the amount of this promissory note to be approximately $250
million.

In July 1997, in accordance  with the  provisions of the LIPA  Transaction,  the
Company and The Brooklyn  Union Gas Company  (Brooklyn  Union)  formed a limited
partnership  and each  Company  invested  $30  million in order to  purchase  an
interest  rate swap  option  instrument  to protect  LIPA  against  market  risk
associated with the municipal bonds expected to be issued by LIPA to finance the
transaction. Upon the closing of the LIPA Transaction, each limited partner will
receive from LIPA $30 million plus  interest  thereon,  based on each  partners'
average weighted cost of capital.  In the event that the LIPA Transaction is not
consummated,  the maximum potential loss to the Company is the amount originally
invested.  In such event,  the Company  plans to defer any loss and petition the
PSC to allow recovery from its customers.

As part of the LIPA Transaction,  the definitive agreements contemplate that one
or more subsidiaries of HoldCo will enter into agreements with LIPA, pursuant to
which such subsidiaries will provide management and operations  services to LIPA
with respect to the electric transmission and distribution system, deliver power
generated  by its power  plants to LIPA,  and manage  LIPA's  fuel and  electric
purchases and any off-system electric sales. In addition,  three years after the
LIPA Transaction is consummated,  LIPA will have the right for a one-year period
to acquire all of  HoldCo's  generating  assets at the fair market  value at the
time of the exercise of the right, which value will be determined by independent
appraisers.

In July 1997,  the New York  State  Public  Authorities  Control  Board  (PACB),
created pursuant to the New York State Public  Authorities Law and consisting of
five members  appointed by the  governor,  unanimously  approved the  definitive
agreements related to the LIPA Transaction subject to the following  conditions:
(i)  within  one  year of the  effective  date  of the  transaction,  LIPA  must
establish a plan for open access to the electric  distribution  system;  (ii) if
LIPA  exercises  its  option  to  acquire  the  generation  assets  of  HoldCo's
generation  subsidiary,  LIPA may not purchase  the  generating  facilities,  as
contemplated in the generation purchase right agreement, at a price greater than
book value; (iii) HoldCo must agree to invest,  over a ten-year period, at least
$1.3 billion in energy-related and economic  development  projects,  and natural
gas infrastructure  projects on Long Island; (iv) LIPA will guarantee that, over
a ten-year period, average electric rates will be reduced


                                       3

<PAGE>

by no less than 14% when measured  against the Company's rates today and no less
than  a 2%  cost  savings  to  LIPA  customers  must  result  from  the  savings
attributable to the merger of LILCO and KeySpan;  and (v) LIPA will not increase
average  electric  customer rates by more than 2.5% over a  twelve-month  period
without  approval from the PSC. LIPA has adopted the conditions set forth by the
PACB. The holders of common and certain series of preferred stock of the Company
eligible to vote approved the LIPA Transaction in August 1997.

In December 1997, the United States Nuclear  Regulatory  Commission (NRC) issued
an order  approving  the  indirect  transfer  of  control of the  Company's  18%
ownership interest in NMP2 to LIPA.

In December 1997, the Company filed with the FERC a settlement agreement reached
with LIPA in connection with a previous  filing of the Company's  proposed rates
for the sale of  capacity  and  energy  to  LIPA,  as  contemplated  in the LIPA
transaction  agreements.  The Company also had  previously  filed an application
with the  FERC  seeking  approval  of the  transfer  of the  Company's  electric
transmission and distribution  system to LIPA in connection with LIPA's purchase
of the common stock of the Company.

In  February  1998,  the FERC  issued  orders  on both of the  Company  filings.
Specifically,  the FERC approved the Company's application to transfer assets to
LIPA in connection  with LIPA's  acquisition of the Company's  common stock.  In
addition,  the FERC accepted the Company's  proposed  rates for sale of capacity
and energy to LIPA.  Those  rates may go into  effect on the date the service to
LIPA begins,  subject to refund,  and final rates will be set after the FERC has
completed  its  investigation  of such  rates,  the  timing  of which  cannot be
determined at this time.

In January  1998,  the Company filed an  application  with the PSC in connection
with  the  proposed  transfer  of its  gas  business  unit  assets,  non-nuclear
generating  facility assets and certain other assets and related  liabilities to
one or more  subsidiaries  of HoldCo to be  formed as  contemplated  in the LIPA
Transaction agreements.  On April 29, 1998, the PSC approved the transfer of the
above-mentioned assets.

In July 1997,  the Company,  Brooklyn  Union and LIPA filed requests for private
letter rulings with the Internal Revenue Service (IRS) regarding certain federal
income  tax  issues  which  require  favorable  rulings  in  order  for the LIPA
Transaction to be consummated. On March 4, 1998, the IRS issued a private letter
ruling  confirming that the sale of the Company's common stock to LIPA would not
result in a corporate tax liability to the Company.  In addition,  the IRS ruled
that,  after the stock sale, the income of LIPA's electric utility business will
not be subject to federal income tax. In a separate ruling on February 27, 1998,
the IRS  also  ruled  that  the  bonds  to be  issued  by LIPA  to  finance  the
acquisition would be tax-exempt.

In January  1998,  the  Company  filed an  application  with the SEC  seeking an
exception for most of the provisions of the Public Utilities Holding Company Act
of  1935.  In May  1998,  the  SEC  issued  an  order  approving  the  Company's
application.

The Company currently  anticipates that the LIPA transaction will be consummated
on or about May 28, 1998.

KEYSPAN ENERGY CORPORATION TRANSACTION
On December 29, 1996,  The Brooklyn Union Gas Company  (Brooklyn  Union) and the
Company  entered  into an  Agreement  and Plan of  Exchange  and  Merger  (Share
Exchange  Agreement),  


                                       4

<PAGE>

pursuant  to which  the  companies  will be  merged  in a  transaction  (KeySpan
Transaction) that will result in the formation of HoldCo.

The Share  Exchange  Agreement  was  amended  and  restated  to reflect  certain
technical changes as of February 7, 1997 and June 26, 1997.  Effective September
29, 1997,  Brooklyn Union  reorganized  into a holding company  structure,  with
KeySpan  Energy  Corporation  (KeySpan)  becoming  its parent  holding  company.
Accordingly,  the parties  entered into an Amendment,  Assignment and Assumption
Agreement, dated as of September 29, 1997, which among other things, amended the
Share  Exchange  Agreement  and related  stock option  agreements to reflect the
assignment  by Brooklyn  Union to KeySpan and the  assumption  by KeySpan of all
Brooklyn Union's rights and obligations under such agreements.

The KeySpan  Transaction,  which has been approved by both companies'  boards of
directors  and  shareholders,  would unite the resources of the Company with the
resources of KeySpan.  KeySpan, 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.  KeySpan  has  energy-related
investments  in gas  exploration,  production and marketing in the United States
and Northern Ireland, as well as energy services in the United States, including
cogeneration projects, pipeline transportation and gas storage.

Under the terms of the KeySpan  Transaction,  the Company's  common  shareowners
will receive 0.803 shares (the Ratio) of HoldCo's common stock for each share of
the Company's common stock that they hold at the time of closing. KeySpan common
shareowners  will  receive  one share of common  stock of HoldCo for each common
share of KeySpan  they hold at the time of closing.  Shareowners  of the Company
will  own  approximately  66%  of the  common  stock  of  HoldCo  while  KeySpan
shareowners will own  approximately  34%. In the event that the LIPA Transaction
is  consummated,  the  Ratio  will be  0.880  with  Company  shareowners  owning
approximately 68% of the HoldCo common stock. Consummation of the Share Exchange
Agreement is not conditioned  upon the  consummation of the LIPA Transaction and
consummation of the LIPA Transaction is not conditioned upon consummation of the
Share  Exchange  Agreement.  Based on  current  facts and  circumstances,  it is
probable  that the  purchase  method of  accounting  will  apply to the  KeySpan
Transaction,  with the  Company  being  the  acquiring  company  for  accounting
purposes.

In March 1997, the Company filed an application  with the FERC seeking  approval
of the transfer of the Company's  common equity and certain  FERC-jurisdictional
assets to HoldCo. In July 1997, the FERC granted such approval.

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.

The Company and KeySpan expect to continue  their  respective  current  dividend
policies until  completion of the KeySpan  Transaction.  It is anticipated  that
HoldCo  will set an  initial  annual  dividend  rate of $1.78  per share for its
common stock.


                                       5

<PAGE>

Upon completion of the merger,  Dr. William J.  Catacosinos will become chairman
and chief executive officer of HoldCo; Mr. Robert B. Catell,  currently chairman
and  chief  executive  officer  of  KeySpan,  will  become  president  and chief
operating officer of HoldCo. 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 HoldCo will be comprised of 15 members, six
from the  Company,  six from  KeySpan and three  additional  persons  previously
unaffiliated with either company.

Effects of LIPA and KeySpan Transactions on Future Operations

The  future   operations   and  financial   position  of  the  Company  will  be
significantly  affected  by each of the  proposed  transactions  with  LIPA  and
KeySpan  described  above.  The  discussion  contained  in this  report  and any
analysis of  financial  condition  and results of  operations  does not reflect,
unless otherwise indicated,  the potential effects of the transactions with LIPA
and KeySpan.  

COMPETITIVE ENVIRONMENT 

A discussion of the  competitive  issues the Company faces appears in Note 12 of
Notes to Financial Statements.

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 1997 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):
<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*            2          382
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          205
Owned by the New York Power Authority:
Holtsville, L.I.                                   Combined Cycle         Dual*            1          142
-------------------------------------------------- ---------------------- ----------- ----------- ---------
       Total                                                                              55        4,325
-------------------------------------------------- ---------------------- ----------- ----------- ---------
</TABLE>

   *Dual - Oil or natural gas.

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 4,140 Megawatts (MW) on July 15,
1997,  representing 84% of the total available capacity of 4,953 MW on that day,
which  included  766 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 


                                       6

<PAGE>

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

For  the  year  ended  March  31,  1998,  system  kilowatt  hours  (kWh)  energy
requirements  on the  Company's  system were 1.0% higher than the  corresponding
1997 period.  The Company  forecasts  increases of 2.3% and 3.2%,  for the years
ending March 1999 and 2000,  respectively  compared to that  experienced for the
year ended March 31, 1998. For the years ending March 31, 2001-2010, the Company
forecasts an average annual growth rate in system energy  requirements  of 1.1%.
Due to the effects of price  elasticity,  the projected peak demand for electric
power is expected to increase if the LIPA  transaction is consummated.  Based on
projections  of peak  demand  for  electric  power  in the  absence  of the LIPA
Transaction,  the Company believes it will need to acquire additional generating
or demand-side  resources  starting in 1998 in order to maintain electric supply
reliability.  In accordance with the Company's Integrated Electric Resource Plan
(IERP), issued in 1996, the Company intends to institute a combination of a peak
load reduction  demand-side  management  program and a capacity purchase to meet
this need. Current  projections are that new electric  generating  capacity will
not need to be installed on Long Island to meet peak demand until after 2002. It
is anticipated  that such new capacity  would be acquired  through a competitive
bidding  process.

Fuel Mix

The megawatt hours (MWh) and  percentages  of total energy  available by type of
fuel for electric  operations  for the years ended March 31, 1998 and 1997,  and
the years ended December 31, 1996 and 1995 were as follows:
<TABLE>
<CAPTION>

                                                                                (In thousands of MWh)
                                            Year Ended                                  Year Ended
                                             March 31,                                 December 31,
                                             ---------                                 ------------
                                     1998                  1997                  1996                  1995
---------------------------------------------------------------------------------------------------------------
                                  MWh      %           MWh       %           MWh       %          MWh        %
---------------------------------------------------------------------------------------------------------------
<S>                             <C>      <C>          <C>      <C>          <C>      <C>          <C>      <C>
Oil                              3,434    20%          3,278    19%          4,219    24%          3,099    17%
Gas                              6,212    35%          5,469    31%          4,542    25%          6,344    36%
Nuclear                          1,545     9%          1,553     9%          1,558     9%          1,301     7%
Purchased power                  6,412    36%          7,261    41%          7,388    42%          7,143    40%
---------------------------------------------------------------------------------------------------------------
Total                           17,603   100%         17,561   100%         17,707   100%         17,887   100%
===============================================================================================================
</TABLE>

Energy Sources

The total energy  provided by oil and natural gas is generated by the  Company's
units located on Long Island,  while the nuclear  generation is provided through
NMP2,  the Company's 18% owned nuclear power plant which is located near Oswego,
New York.

Oil
The availability and cost of oil used by the Company is affected by factors 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 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.  The Company's fuel oil is
supplied principally by three suppliers.


                                       7

<PAGE>

Oil consumption in barrels was as follows:
-----------------------------------------------------------------------------
              Years Ended                Consumption (in barrels)
-----------------------------------------------------------------------------
-----------------------------------------------------------------------------
            March 31, 1998                      5.6 million
-----------------------------------------------------------------------------
-----------------------------------------------------------------------------
            March 31, 1997                      5.5 million
-----------------------------------------------------------------------------
-----------------------------------------------------------------------------
           December 31, 1996                    7.1 million
-----------------------------------------------------------------------------
-----------------------------------------------------------------------------
           December 31, 1995                    5.2 million
-----------------------------------------------------------------------------

Natural Gas
Nine of the  Company's  eleven steam  generating  units have the  capability  of
burning  natural gas.  Seven of these units 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 April 1996 and May 1997, the Company  completed
two  planned  conversions  of  oil-fired  steam  generating  units  at its  Port
Jefferson Power Station to dual-firing units.

Gas consumption for electric generation was as follows:
----------------------------------------------------------------------------
              Years Ended           Consumption (in million Dth)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
            March 31, 1998                      69.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
            March 31, 1997                      63.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
           December 31, 1996                    50.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------
           December 31, 1995                    69.8
----------------------------------------------------------------------------

The percentage of energy generated by burning natural gas at the Company's steam
and internal combustion units was as follows:

----------------------------------- --------------------------------
           Years Ended                    Percent Generated
----------------------------------- --------------------------------
----------------------------------- --------------------------------
          March 31, 1998                         64%
----------------------------------- --------------------------------
----------------------------------- --------------------------------
          March 31, 1997                         63%
----------------------------------- --------------------------------
----------------------------------- --------------------------------
        December 31, 1996                        52%
----------------------------------- --------------------------------
----------------------------------- --------------------------------
        December 31, 1995                        67%
----------------------------------- --------------------------------

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  206 MW of  capacity  to the Company
during the year ended March 31, 1998.

The  percentage  of the total  energy  made  available  to the  Company by IPPs,
cogenerators and the NYPA Holtsville facility was follows:
----------------------------------- ---------------------------------------
           Years Ended                   Percent of Energy Available
----------------------------------- ---------------------------------------
----------------------------------- ---------------------------------------
          March 31, 1998                            17.2%
----------------------------------- ---------------------------------------
----------------------------------- ---------------------------------------
          March 31, 1997                            16.1%
----------------------------------- ---------------------------------------
----------------------------------- ---------------------------------------
        December 31, 1996                           16.1%
----------------------------------- ---------------------------------------
----------------------------------- ---------------------------------------
        December 31, 1995                           16.3%
----------------------------------- ---------------------------------------


                                       8

<PAGE>

The Company  does not expect any new major IPPs or  cogenerators  to be built on
Long Island in the near future.  Among the reasons supporting this conclusion is
the Company's  belief that the market for IPPs and cogenerators to provide power
to the  Company's  remaining  commercial  and  industrial  customers  is  small.
Furthermore,  under  federal  law,  the  Company is  required to buy energy from
qualified  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  with respect to competitive  issues
facing the Company, see Note 12 of Notes to Financial Statements.

Nuclear

The Company holds an 18% interest in NMP2, an 1,137 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%). For the
year ended  March 31,  1998,  NMP2  operated  at 86.63% of its  capacity.  For a
further discussion of NMP2, see Note 5 of Notes to Financial Statements.

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."

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
10 of Notes to Financial Statements.

Electric Rates

A  discussion  of  electric  rates  appears  in  Note 4 of  Notes  to  Financial
Statements.


                                       9

<PAGE>

GAS OPERATIONS
General
The Company's gas supplies are transported by interstate pipelines from Canadian
and domestic sources.  On-system peak shaving and IPP/Cogen peaking supplies are
available to meet system requirements during winter periods.

During the past several years, 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 decrease upstream  transportation  costs and 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  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 March 31, 1998, there were approximately 3,600 NaturalChoice(sm) customers
with annual  requirements  of  approximately  4,213,000  Dth or 7 percent of the
Company's annual gas system requirements.

Gas System Requirements

The Company has 467,000 firm gas customers at March 31, 1998,  including 295,000
gas space heating  customers,  an increase of more than 15,000 gas space heating
customers over the past three years. The Company's  penetration in the gas space
heating market within its service territory is approximately 29%.

Total firm sales for the year ended March 31, 1998, when normalized for weather,
decreased approximately 3.6% over the comparable period in 1997 primarily due to
customers switching to the NaturalChoice(sm)  Program. 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 1998-1999  winter season (November 1 -
March  31) is  approximately  652,000  Dth,  or 88%  of the  Company's  peak-day
capability.


                                       10

<PAGE>

Peak Day Capability

The  Company  has firm  gas  peak day  capability  in  excess  of its  projected
requirements  for firm gas customers for the 1998-1999  winter season  (November
1-March 31). Firm capability is summarized in the following table:

---------------------------------------------------- --------------------
                              Dth per day               % of Total
---------------------------------------------------- --------------------
Transportation                    263,000                     35
Storage                           294,000                     40
Cogen/IPP Deliveries               85,000                     11
Peak Shaving                      103,000                     14
==================================================== ====================
Total                             745,000                     100%
==================================================== ====================

Transportation
The Company has available under firm contract  263,000 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  majority  interest  in a  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 Pennsylvania and New York which provide a total
maximum  supply of 294,000 Dth per day, with a total  capacity of 22,534,000 Dth
for the winter period.

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.
However,  the Company has no incremental firm pipeline  transportation  capacity
for these supplies.

Cogen/IPP Deliveries
The Company has contract  rights with the Brooklyn  Navy Yard Cogen  facility to
receive  approximately  576,000 Dth of peaking supplies during the winter period
at a rate of  approximately  30,000 Dth per day.  Also, the Company has contract
rights with the Nassau  District  Energy  Corporation to receive  250,000 Dth of
peaking supplies during the winter period at a rate of 12,500 Dth per day.

The Company has contract  rights with the NYPA IPP  facility to receive  900,000
Dth of storage  service during any continuous  100-day period during each winter
season at a daily  rate not to  exceed  31,000  Dth per day.  In  addition,  the
Company has contract  rights with  Nissequogue  Cogen  facility to receive up to
330,000 Dth of storage  service for 30 days during each winter season at a daily
rate not to exceed 11,000 Dth per day. The Company has the  obligation to return
these  quantities in kind during the following summer period.  In addition,  the
Company has the right to request  812,000 Dth in the winter  season from the TBG
Cogen  facility with the  obligation to return the quantities in kind during the
following  summer period.  The daily quantity of 12,500 Dth is only available on
warmer winter days.

Peak Shaving
The Company has its own peak shaving  supplies to meet its firm  requirements on
excessively cold winter days. They include a liquefied  natural gas plant with a
storage capacity of approximately 600,000 Dth and vaporization  facilities which
provide  approximately  103,000 Dth per day to the  


                                       11

<PAGE>

peak-day capability of the Company's system.

Firm Gas Supply
The Company has approximately  161,000 Dth per day of firm gas supplies that are
transported under its firm pipeline  transportation  capacity.  About 83,000 Dth
per day is  obtained  from  Canadian  sources and 78,000 Dth per day is obtained
from  domestic  sources.  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's  161,000 Dth per day of long-term  supply contracts have 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
associated demand charges.

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.

Gas Rates
A discussion of gas rates appears in Note 4 of Notes to Financial Statements.

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 modifying 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  transition
costs,  the Company  estimates that it will be responsible for total  transition
costs of  approximately  $10  million.  As of March 31,  1998,  the  Company has
collected $8.7 million of these transition costs from its gas customers.

Natural Gas Vehicles
The Company  continues  to maintain a focus on  promoting  Natural Gas  Vehicles
(NGVs) and infrastructure development.  Additional resources have been dedicated
to the NGV  program  in 1997 and 1998 and an  arrangement  with a company  named
Fuelmaker has provided customers with a low risk, low cost approach to refueling
their NGVs. In addition, consistent with a Clean Cities designation, the Company
has  aggressively  assisted  customers in obtaining  Congestion  Mitigation  Air
Quality (CMAQ) grants and other  Department of Energy funds to help offset their
incremental  NGV and refueling  equipment  costs.  As a result of these efforts,
NGVs consumed  approximately 130,000 Dth and resulted in $260,000 in revenue net
of fuel for the year ended March 31, 1998.

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  


                                       12

<PAGE>

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 (CERCLA, commonly known as Superfund), the federal Resource Conservation and
Recovery Act, the federal Toxic Substances Control Act (TSCA), the federal Clean
Water Act (CWA), and the federal Clean Air Act (CAA).

Capital expenditures for environmental improvements and related studies amounted
to  approximately  $9.2 million for the year ended March 31, 1998 and,  based on
existing  information,  are expected to be $4.0 million for the year ended March
31, 1999. The  expenditures in fiscal year 1998 and expected  spending in fiscal
year 1999 include a total of $10.6  million for the  completion  of a gas-firing
capability project at Northport Unit 1 and Port Jefferson Unit 4.

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  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 from its customers.

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,  as 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  presently  applies the proceeds  resulting from any sales of excess
SO2 allowances as a reduction to the RMC balance.

The Company entered into a voluntary  Memorandum of  Understanding  with the DEC
which  


                                       13

<PAGE>

provides that the Company will not sell SO2  allowances  for use in 15 states in
an effort to mitigate the transport of acid rain  precursors into New York State
from upwind states.

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  rate of all the
utilities  in New York State for the years ended  December  31,  1997,  1996 and
1995.  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.
It is estimated that additional expenditures of approximately $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  $10 million to $34
million,  excluding  the Northport  Unit 1 conversion,  by the year 2003 to meet
Phase III NOx  reduction  requirements.  The  completion  of the  project to add
gas-firing capability at Northport Unit 1 (completed in May 1998 at a total cost
of  approximately  $8.4 million) will also  facilitate the Company's  compliance
with the anticipated Phase III Nox reduction requirements.

Continuous Emission Monitoring
Additional software and equipment upgrades for Continuous  Emissions Monitors of
approximately  $2  million  may be  required  through  1999  at  all  generating
facilities  in order  to meet EPA  requirements  under  development  for the NOx
allowance tracking/trading 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 $1.5 million in fiscal 1998 and
the planned  spending of $0.5 million through March 31, 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  approximately  23%
since  1990,  largely  through  greater  reliance  on the use of natural gas and
through conservation programs.  This makes the Company less vulnerable to future
CO2 reduction requirements.

Opacity Issues

The DEC  has  proposed  commencing  enforcement  actions  against  all New  York
utilities  for  alleged  opacity  exceedences  from  steam  electric  generating
facilities. Opacity is a measure of the relative level of light that is obscured
from passing through a power plant stack emission  plume.  An exceedence  occurs
when the level of light  passing  through  the plume is reduced by more than 20%


                                       14

<PAGE>

for six minutes or more. The Company has entered into an Administrative  Consent
Order (ACO) with the DEC which  resolves  all  historical  opacity  exceedences,
establishes an opacity  reduction  program to be undertaken by the Company,  and
sets a  stipulated  penalty  schedule  for  future  exceedences.  The  number of
exceedences  experienced by the Company is relatively  low,  placing the Company
among the best performers in New York State.

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,  four  residential  property  owners  have
initiated  separate  lawsuits against the Company alleging that the existence of
EMF  has  diminished  the  value  of  their  homes.  These  actions  are  in the
preliminary  stages of  discovery  and are  similar to actions  brought  against
another New York State utility, which were dismissed by the New York State Court
of Appeals.  The Company is not involved in any active litigation that alleges a
causal relationship between exposure to EMF and adverse health effects.

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 fiscal year 1998,  the Company  spent  approximately  $300,000 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  $100,000 in
the years 1998-2000.

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 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.


                                       15

<PAGE>

The Owners  have also  entered  into an ACO with the DEC as a result of leaks of
dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to
participate  in and  separately  approve the reports and studies being  prepared
pursuant  to the ACO issued by the DEP.  In  addition,  the ACO  settles any DEC
claim for natural  resource  damages in connection with  historical  releases of
dielectric fluid from the Sound Cable.

In October 1995, 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 December 1996, a barge,  owned and operated by a third party,  dropped anchor
which then dragged over and damaged the Sound Cable, resulting in the release of
dielectric fluid into Long Island Sound.  Temporary clamps and leak abaters were
installed on the cables to stop the leaks.  Permanent  repairs were completed in
June 1997. The cost to repair the Sound Cable was  approximately  $17.8 million,
for which there was $15 million of insurance coverage.  The Owners filed a claim
and answer in response to the maritime limitation  proceeding  instituted by the
barge owner in the United States District Court,  Eastern  District of New York.
The claim seeks recovery of the amounts paid by insurance  carriers and recovery
of the costs  incurred for which there was no insurance  coverage.  Any costs to
repair the Sound Cable which are 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 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.  In January 1998,  the
Company  commenced a similar  action  against  the same and  certain  additional
insurer  defendants  in New York State  Supreme  Court,  First  Department;  the
federal court action was  subsequently  dismissed in March 1998.  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  


                                       16

<PAGE>

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,  completed  performance of a Remedial
Investigation  and Feasibility  Study (RI/FS),  which was conducted under an ACO
with the EPA. In  December  1997,  the EPA issued its Record of Decision  (ROD),
setting forth the final remedial  action  selected for the site. In the ROD, the
EPA estimated that the present cost of the selected remedy for the site is $17.3
million. At this time, the Company cannot predict with reasonable  certainty the
actual cost of the selected remedy,  who will implement the remedy, or the cost,
if  any,  to the  Company.  Under a PRP  participation  agreement,  the  Company
previously was responsible for 8.2% of the costs  associated with the RI/FS. The
Company's  allocable share of liability for the  remediation  activities has not
yet been determined.

The Company has recorded a liability of  approximately  $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. For a further  discussion on this matter,  see Item 3, Legal
Proceedings - Environmental.

PCB Treatment, 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
Treatment, 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.

Certain of the PRPs, including the Company and several other utilities, formed a
PRP  group,  signed an ACO,  and have  developed  a workplan  for  investigating
environmental  conditions at the sites.  Documentation connecting the Company to
the sites  indicates  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.

Osage
The EPA has  notified  the Company  that it is a PRP at the Osage Metals Site, a
former scrap metal  recycling  facility  located in Kansas City,  Kansas.  Under
Section  107(a) of CERCLA,  parties  who  arranged  for  disposal  of  hazardous
substances  are liable for costs  incurred by the EPA in responding to a release
or threat of release of the hazardous substances.  Osage had purchased capacitor
scrap metal from PCB Treatment,  Inc. Through the arrangements  that the Company
made with PCB Treatment,  Inc. to dispose of capacitors,  the Company is alleged
to have arranged for disposal within the meaning of the federal Superfund law. A
similar  letter was sent to 861 parties who sent  capacitors  to PCB  Treatment,
Inc.  The EPA is  seeking  to  recover  approximately  $1.1  million  dollars it
expended  to conduct a removal  action at the site.  The  Company  is  currently


                                       17

<PAGE>

unable to determine its share of the $1.1 million expenditure.

Port Refinery
The Company has been notified  that it is a PRP at the Port  Refinery  Superfund
site located in Westchester  County,  New York. Port Refinery was engaged in the
business of purchasing, selling, refining and processing mercury and the Company
may have shipped a small  amount of waste  products  containing  mercury to this
site.  Tests  conducted by the EPA indicated that the site and certain  adjacent
properties were contaminated with mercury.  As a result, the EPA has performed a
response action at the site and seeks to recover its costs,  currently  totaling
approximately $4.4 million,  plus interest,  from the PRPs. The Company does not
believe its portion of these costs, if any, will be material.

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 sent any materials to
the site that contributed to the  contamination  which requires  remediation and
has  therefore  declined  the EPA's  requests  to  participate  in  funding  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  transformers.  The Company is currently unable to determine
its share of costs of remediation at this site.

Huntington/East Northport
The DEC has notified the Company,  pursuant to the State Superfund program, that
its records indicate the Company may be responsible for the disposal of waste at
this  municipal  landfill  property.  The  Company  conducted  a  search  of its
corporate  records and did not locate any documents  concerning  waste  disposal
practices  associated  with this  landfill.  The Company is currently  unable to
determine its share,  if any, of the costs to  investigate  and  remediate  this
site.

Blydenburgh

The New York State Office of the Attorney  General has notified the Company that
it may be  responsible  for the disposal of wastes and/or for the  generation of
hazardous  substances  which  may  have  been  disposed  of at  the  Blydenburgh
Superfund  site,  a municipal  sanitary  landfill  located in the Town of Islip,
Suffolk County.  The State has incurred  approximately  $15 million in costs for
the investigation  and remediation of environmental  conditions at the landfill.
In  connection  with this  notification,  the Company  conducted a review of its
corporate  records and did not locate any documents  concerning  waste  disposal
practices  associated  with this  landfill.  The Company is currently  unable to
determine its share,  if any, of the costs to  investigate  and  remediate  this
site.

Other Sites

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


                                       18

<PAGE>

disposal of certain waste products located at these sites.

The Company has entered into discussions with the DEC which are expected to 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  preliminary
investigations  conducted at each of these six sites, current estimates indicate
that it may cost  approximately  $54 to $92 million to investigate and remediate
all of these sites. Considering the range of possible remediation estimates, the
Company felt it  appropriate  to record a $54 million  liability  reflecting the
present  value of the future  stream of  payments  amounting  to $70  million to
investigate and remediate these sites. The Company used a risk-free rate of 6.0%
to discount this obligation.  The Company believes that the PSC will provide for
future recovery of these costs and has recorded a $54 million  regulatory asset.
The  Company's  rate  settlement  which  the PSC  approved  February  4, 1998 as
discussed in Note 3 of Notes to Financial Statements, allows for the recovery of
MGP expenditures from gas customers.

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.

North Hills Leak

The Company has undertaken remediation of certain soil locations in North Hills,
New York that were impacted by a release of insulating  fluid from an electrical
cable in August 1994. The Company  estimates  that any additional  cleanup costs
will not exceed $0.5 million.  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.

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.  To the extent  that these costs are not
recoverable through insurance carriers,  the Company believes such costs will be
recoverable from its customers.

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 at least  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.


                                       19

<PAGE>

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 2012.

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 IBCA, Inc. 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."

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
March 31, 1998 and 1997 were approximately $1.3 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  $5.2 billion of additional  G&R Bonds based upon net earnings for
the year ended  March 31,  1998 and an assumed  interest  rate of 7.75% 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 $82 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  $1.5
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,  1997 is $25  million.  The  Company  believes  that,  based upon  currently
scheduled redemptions and maturities,  it will 


                                       20

<PAGE>

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 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,  1997,  the amount of such  cumulative  property
additions  calculated  pursuant  to the G&R  Mortgage  was  approximately  $10.4
billion, including approximately $5.5 billion of property additions attributable
to  Shoreham.  Also,  as of  December  31,  1997,  the amount of the  cumulative
provision  for  depreciation,   similarly  calculated,  was  approximately  $2.0
billion. The Company anticipates that the aggregate amount of property additions
will continue to exceed the cumulative provision for depreciation.

For a discussion  of the effect the LIPA  Transaction  will have on Company debt
outstanding, see Long Island Power Authority Transaction, above.

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 March 31, 1998 and 1997, there were approximately
$2.3 billion of debentures outstanding.  For a discussion of the effect that the
LIPA Transaction will have on the Company's G&R Bonds and Debentures,  see "Long
Island Power Authority Transaction," above.

As of March 31, 1998,  the Company had  outstanding  approximately  $941 million
principal amount of promissory notes, comprised of: (i) $2 million of tax-exempt
Industrial Development Revenue Bonds (IDRBs); (ii) approximately $214 million of
tax-exempt  Pollution  Control Revenue Bonds (PCRBs);  and (iii) $725 million of
tax-exempt Electric Facilities Revenue Bonds (EFRBs). Of these amounts,  certain
series are subject to periodic tenders.  For a discussion of the effect that the
LIPA  Transaction  will have on the  Company's  tax exempt  authority  financing
notes, see "Long Island Power Authority Transaction," above.

For additional information respecting tender provisions and other information on
the Company's outstanding debt, see Note 7 of Notes to Financial Statements.

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 


                                       21

<PAGE>

comply with provisions of the Company's  Restated  Certificate of  Incorporation
and the  availability  of  retained  earnings,  future  earnings  and cash.  For
additional information with respect to the Company's common stock, see Note 6 of
Notes to Financial Statements.

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). At March 31, 1998,
the Company  satisfied  the Earnings  Ratio and could issue up to  approximately
$1,076 million of preferred stock at an assumed dividend rate of 8.25%. 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. For
additional information with respect to the Company's preferred stock, see Note 6
of Notes to Financial Statements.

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.


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<PAGE>

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,  68, a resident  of Mill Neck,  Long  Island,  earned a
bachelor of science degree,  a masters degree in business  administration  and a
doctoral  degree in economics  from New York  University.  Dr.  Catacosinos is a
member of the Boards of Atlantic Bank of New York,  the Long Island  Association
and  the  Empire  State  Business  Alliance,  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,  43, 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.

Michael E. Bray:  Senior Vice  President  of the  Electric  Business  Unit since
joining  the  Company in March  1997.  Prior to joining the Company Mr. Bray was
President and CEO of DB Riley  Consolidated  in Worcester,  Massachusetts.  From
1987-1994 Mr. Bray was with ABB Power Generation,  Inc. in Windsor,  Connecticut
holding the positions of Senior Vice  President  Sales & Marketing for ABB Power
Generation and President of ABB's Resource Recovery Systems organization.  Prior
to that, he spent 17 years with General  Electric  Company  beginning as a field
engineer in the power equipment  service  organization  and ultimately  managing
General  Electric's   cogeneration   development,   construction  and  operating
organization.  Mr. Bray,  50, holds a bachelor of science  degree in  mechanical
engineering  from the  University  of Missouri at Rolla and a masters  degree in
Business Administration from Washington University.  Mr. Bray is a member of the
American  Academy of  Mechanical  Engineers,  past Board of  Director/member  of
American Boiler  Manufacturer's  Association and the Greater Hartford Chamber of
Commerce.  He is also a charter member of the Academy of Mechanical Engineers at
the University of Missouri at Rolla.

Charles A. Daverio:  Vice President of The Energy  Exchange Group since December
1996,  Mr.  Daverio,  48, 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 


                                       23

<PAGE>

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.

Jane A.  Fernandez:  Vice  President  of Human  Resources  since May  1997,  Ms.
Fernandez  joined the  Company  in 1973 and has held  various  positions  in the
Employee  Relations/Human  Resources  organization  since  that  time.  She  was
Director  of  Human  Resource  Planning  from  1988 to 1990,  Director  of Human
Resource  Services from 1990 to 1994,  Director of Corporate  Training and Human
Resources in 1994, and Assistant Vice President of Human  Resources from 1994 to
1997. Ms. Fernandez, 48, is a graduate of C. W. Post College and holds an MBA in
Management from Hofstra University.

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,   64,  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 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  and the New York  State
Society of CPAs. Before joining the Company, Mr. Fontana was a Senior Manager at
the international  accounting firm of Ernst & Young, LLP. Mr. Fontana, 40, holds
a bachelor of science degree in accounting from Westchester State College and is
a Certified Public Accountant.

George B. Jongeling:  Vice President of Special Projects since April 1998. Prior
to joining the Company,  Mr. Jongeling was President and Chief Operating Officer
of Smith  Cogeneration  Company,  an Independent Power Development  Company with
active  independent  power  development in Asia and operating plants in the U.S.
Previous  assignments  included Vice  President of Operations  and Member of the
Board of Directors of DB Riley,  President of PACE  Construction  Company,  Vice
President  of Service  and Spare  Parts for ABB Gas  Turbine  Business  and Vice
President of Business  Development for ABB waste to energy business.  He started
his career in 1966 as a field  engineer  for the  General  Electric  Company and
spent 24 years working in the power generation  business in domestic and foreign
management positions. His last General Electric assignment was as Manager of the
Eastern  Region of the U.S.  for the  Systems  Marketing  Group  supporting  the
cogeneration, construction, development and O&M businesses for General Electric.
Mr.  Jongeling,  54,  received  a  Bachelor  of  Science  degree  in  Mechanical
Engineering  from the  South  Dakota  School of Mines  and  Technology  and is a
licensed professional engineer in Illinois and Missouri.

Robert X. Kelleher: Senior Vice President of Human Resources since May 1997, 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, Assistant Vice President of
the Employee Relations Department from 1985 to 1986, and Vice President of Human
Resources  from 1986 to 1997.  Mr.  Kelleher,  61, is a graduate of St.  


                                       24

<PAGE>

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 The Edison Electric Institute's Labor Relations
Committee.

John D. Leonard,  Jr.: Vice President of Special  Projects since April 1997, Mr.
Leonard joined the Company in 1984 as Vice President of Nuclear  Operations.  He
continues to be  responsible  for nuclear  issues.  Mr.  Leonard  served as Vice
President of Engineering  and  Construction  from March 1994 through March 1997,
and  previously  served 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 65 and a Licensed  Professional  Engineer in the State of
New York.

Adam M. Madsen:  Senior Vice President of Corporate and Strategic Planning since
1984, Mr. Madsen,  61, 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 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 April 1992. Ms. Marion,  43, 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  Communications  since February 1997, Mr.
McCaffrey  joined the Company in 1973.  Mr.  McCaffrey,  52, 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 his present  assignment,  Mr.  McCaffrey was
Vice President of Administration since 1987. Previously, 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  


                                       25

<PAGE>

from 1984 through 1987 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,  46,
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,  where he 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 the  Association  of the Bar of the City of New
York.  He is also a member of the  Executive  Committee of the CPR Institute for
Dispute Resolution.  Mr. Novello, 57, 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,  49, 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.  Mr.  Nozzolillo  is chairman of the  Community  Advisory  Board of
Lawrence Public Schools' "School to Career Initiative."

Richard Reichler:  Deputy General Counsel and Vice President of Tax Planning and
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,  63, 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, 54, 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,  


                                       26

<PAGE>

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,  38,  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.

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,  51, 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,  61, 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  Facilities  and Real Estate since
February 1997, Mr.  Steiger,  54, held the positions of Vice President of Fossil
Production  from  April  1994  through  February  1997  and  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 Engineering & Construction  since
February  1997,  Mr.  Youngling  joined the Company in 1968 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.  In April 1994 he was named Senior Vice  President of the Electric
Business  Unit.  Mr.  Youngling,  53,  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. Mr. Youngling also serves on the
Eastern Advisory Board of the Protection Mutual Insurance Company.


                                       27

<PAGE>

CAPITAL REQUIREMENTS, LIQUIDITY AND CAPITAL PROVIDED

Information as to "Capital  Requirements,"  "Liquidity"  and "Capital  Provided"
appears in Item 7, "Management's  Discussion and Analysis of Financial Condition
and Results of Operations."

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 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.


                                       28

<PAGE>

In  November  1996,  the  Supreme  Court  ruled  that  Shoreham  had  also  been
over-assessed  for real  property  tax  purposes  for Phase II. A  judgment  was
entered on March 26, 1997 in the amount of $868,478,912  which includes interest
to November 4, 1996.  Suffolk  County,  the Town of Brookhaven  and the Shoreham
Wading-River Central School District have appealed the judgment to the Appellate
Division,  Second  Department.  All  briefs  have been  filed and oral  argument
occurred on May 6, 1998. The Court reserved decision.  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 additional 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  1933 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. An agreement in principal has been reached
between the Company,  certain  other  defendants,  the State of New York and the
Town; any settlement is subject to court approval and if approved would not 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 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 


                                       29

<PAGE>

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 issued an Order dated  August 26, 1997 which  denied both  motions  except
that it dismissed  Plaintiffs' cause of action alleging  violation of the Public
Trust  Doctrine and prohibited the Town of Riverhead from suing in its sovereign
capacity.  The  parties  have filed  notices of intent to appeal  this order and
discovery has commenced.  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  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. Kelleher,  the Plan
Administrator,  in the United States District Court for the Eastern  District of
New York (Becher,  et al. v. Long Island Lighting  Company,  et al.). In January
1996,  the Court ordered that this action be maintained as a class action.  This
proceeding arose in connection with the plaintiffs' withdrawal, approximately 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.  In
November 1997, the Company filed a motion for partial summary  judgment with the
District  Court.  On April 28, 1998,  the Court denied the Company's  motion and
permitted the Company to file a further motion for partial summary  judgement on
additional grounds.  The Company maintains that the plaintiff's claims
are without merit and intends to defend against said claims.

OTHER MATTERS

A discussion  of legal  proceedings  related to  competitive  issues  facing the
Company appears in Note 12 of Notes to Financial Statements.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None


                                       30

<PAGE>
                                     PART II

Item 5.  Market  for the  Registrant's  Common  Equity and  Related  Stockholder
Matters At March 31, 1998, the Company had 78,314  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.

The high and low market prices of the  Company's  common stock and dividends per
common share for 1996, 1997 and the first quarter of calendar 1998 are set forth
on the table below.
<TABLE>
<CAPTION>

----------------------------------------------------- ------------------------------------------------------------------
                                                                     Fiscal Year Ended March 31, 1998
                                                      ------------------------------------------------------------------
3 Months Ended                             3/31/97          6/30/97         9/30/97         12/31/97          3/31/98
------------------------------------- --------------- ----------------- --------------- --------------- ----------------
<S>                                         <C>             <C>             <C>                 <C>            <C>

Market price of common stock
 High                                         24 1/2         24 1/8          26                  30 1/2        31 5/8
 Low                                          21 3/4         22              22 3/4              24 1/8        27 15/16
Dividends per common share                   .445           .445            .445                .445          .445
-------------------------------------- -------------- ----------------- -------------- ----------------- --------------

----------------------------------------------------- ----------------------------------------------------------------
                                                                  Calendar Year Ended December 31, 1996
                                                      ----------------------------------------------------------------
3 Months Ended                                             3/31/96          6/30/96         9/30/96        12/31/96
------------------------------------- --------------- --------------- ---------------- --------------- ---------------
Market price of common stock
 High                                                       18 1/8           17 7/8          17 3/4          22 3/8
 Low                                                        15 7/8           16 1/8          16 5/8          17 1/8
Dividends per common share                                  .445             .445            .445            .445
-------------------------------------- -------------- --------------- ---------------- --------------- ---------------
</TABLE>


                                       31

<PAGE>

<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA                                              (In thousands of dollars except per share amounts)
------------------------------------------------------------------------------------------------------------------------------------
                                                                  March 31           March 31      December 31         December 31  
For the year ended                                                  1998               1997             1996             1995       
------------------------------------------------------------------------------------------------------------------------------------
REVENUES                                  
<S>                                                            <C>                <C>                  <C>             <C>          
Electric                                                       $  2,478,435       $  2,464,957         2,466,435       $  2,484,014 
Gas                                                                 645,659            672,705           684,260            591,114 
------------------------------------------------------------------------------------------------------------------------------------
Total Revenues                                                    3,124,094          3,137,662         3,150,695          3,075,128 
------------------------------------------------------------------------------------------------------------------------------------

OPERATING EXPENSES
Operations - fuel and purchased power                               957,807            954,848           963,251            834,979 
Operations - other                                                  400,045            372,880           381,076            383,238 
Maintenance                                                         111,120            116,988           118,135            128,155 
Depreciation and amortization                                       158,537            154,921           153,925            145,357 
Base financial component amortization                               100,971            100,971           100,971            100,971 
Rate moderation component amortization                              (35,079)            (2,999)          (24,232)            21,933 
Regulatory liability component amortization                         (79,359)           (79,359)          (79,359)           (79,359)
1989 Settlement credits amortization                                 (9,213)            (9,213)           (9,214)            (9,214)
Other regulatory amortization                                        47,272            112,294           127,288            161,605 
Operating taxes                                                     466,326            469,561           472,076            447,507 
Federal income tax - current                                         86,388             52,737            42,197             14,596 
Federal income tax - deferred and other                             150,983            157,873           168,000            193,742 
------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                          2,355,798          2,401,502         2,414,114          2,343,510 
------------------------------------------------------------------------------------------------------------------------------------
Operating Income                                                    768,296            736,160           736,581            731,618 
------------------------------------------------------------------------------------------------------------------------------------

OTHER INCOME AND (DEDUCTIONS)
Rate moderation component carrying charges                           23,632             25,279            25,259             25,274 
Other income and deductions, net                                    (18,156)            13,921            19,197             34,400 
Class Settlement                                                    (15,623)           (19,895)          (20,772)           (21,669)
Allowance for other funds used during construction                    3,846              2,886             2,888              2,898
Federal income tax - current                                            594                 --                --                 -- 
Federal income tax - deferred and other                               4,124               (723)              940              2,800 
------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and (Deductions)                                  (1,583)            21,468            27,512             43,703 
------------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges                                      766,713            757,628           764,093            775,321 
------------------------------------------------------------------------------------------------------------------------------------

INTEREST CHARGES
Interest on long-term debt                                          351,261            372,108           384,198            412,512 
Other interest                                                       57,805             66,818            67,130             63,461 
Allowance for borrowed funds used during construction                (4,593)            (3,707)           (3,699)            (3,938)
------------------------------------------------------------------------------------------------------------------------------------
Total Interest Charges                                              404,473            435,219           447,629            472,035 
------------------------------------------------------------------------------------------------------------------------------------

NET INCOME                                                          362,240            322,409           316,464            303,286 
Preferred stock dividend requirements                                51,813             52,113            52,216             52,620 
------------------------------------------------------------------------------------------------------------------------------------

EARNINGS FOR COMMON STOCK                                      $    310,427       $    270,296           264,248       $    250,666 
====================================================================================================================================

AVERAGE COMMON SHARES OUTSTANDING (000)                             121,415       $    120,620           120,360            119,195 
------------------------------------------------------------------------------------------------------------------------------------

BASIC AND DILUTED EARNINGS PER COMMON SHARE                    $       2.56               2.24              2.20       $       2.10 
====================================================================================================================================

Common stock dividends declared per share                      $       1.78               1.78              1.78       $       1.78 
Common stock dividends paid per share                          $       1.78               1.78              1.78       $       1.78 
Book value per common share at                                 $      21.88              21.07             20.89       $      20.50 
Common shares outstanding at (000)                                  121,681            120,987           120,781            119,655 
Common shareowners of record at                                      78,314             77,691            86,607             93,088 
====================================================================================================================================

TOTAL ASSETS                                                   $ 11,900,725       $ 11,849,574        12,209,679       $ 12,527,597 
LONG-TERM DEBT                                                 $  4,381,949       $  4,457,047         4,456,772       $  4,706,600 
PREFERRED STOCK - REDEMPTION REQUIRED                          $    562,600       $    638,500           638,500       $    639,550 
PREFERRED STOCK - NO REDEMPTION REQUIRED                       $         --       $     63,598            63,664       $     63,934 
COMMON SHAREOWNERS' EQUITY                                     $  2,662,447       $  2,549,049         2,523,369       $  2,452,953 


<PAGE>

ITEM 6. SELECTED FINANCIAL DATA                (In thousands of dollars except per share amounts)
-------------------------------------------------------------------------------------------------
                                                                  December 31        December 31 
For the year ended                                                   1994                1993    
-------------------------------------------------------------------------------------------------
<S>                                                              <C>                <C> 

REVENUES                                                                                         
Electric                                                         $  2,481,637       $  2,352,109 
Gas                                                                   585,670            528,886 
------------------------------------------------------------------------------------------------ 
Total Revenues                                                      3,067,307          2,880,995 
------------------------------------------------------------------------------------------------ 
                                                                                                 
OPERATING EXPENSES                                                                               
Operations - fuel and purchased power                                 847,986            827,591 
Operations - other                                                    406,014            387,808 
Maintenance                                                           134,640            133,852 
Depreciation and amortization                                         130,664            122,471 
Base financial component amortization                                 100,971            100,971 
Rate moderation component amortization                                197,656             88,667 
Regulatory liability component amortization                           (79,359)           (79,359)
1989 Settlement credits amortization                                   (9,214)            (9,214)
Other regulatory amortization                                           4,328            (18,044)
Operating taxes                                                       406,895            385,847 
Federal income tax - current                                           10,784              6,324 
Federal income tax - deferred and other                               170,997            178,530 
------------------------------------------------------------------------------------------------ 
Total Operating Expenses                                            2,322,362          2,125,444 
------------------------------------------------------------------------------------------------ 
Operating Income                                                      744,945            755,551 
------------------------------------------------------------------------------------------------ 
                                                                                                 
OTHER INCOME AND (DEDUCTIONS)                                                                    
Rate moderation component carrying charges                             32,321             40,004 
Other income and deductions, net                                       35,343             38,997 
Class Settlement                                                      (22,730)           (23,178)
Allowance for other funds used during construction                      2,716              2,473 
Federal income tax - current                                               --                 -- 
Federal income tax - deferred and other                                 5,069             12,578 
------------------------------------------------------------------------------------------------ 
Total Other Income and (Deductions)                                    52,719             70,874 
------------------------------------------------------------------------------------------------ 
Income Before Interest Charges                                        797,664            826,425 
------------------------------------------------------------------------------------------------ 
                                                                                                 
INTEREST CHARGES                                                                                 
Interest on long-term debt                                            437,751            466,538 
Other interest                                                         62,345             67,534 
Allowance for borrowed funds used during construction                  (4,284)            (4,210)
------------------------------------------------------------------------------------------------ 
Total Interest Charges                                                495,812            529,862 
------------------------------------------------------------------------------------------------ 
                                                                                                 
NET INCOME                                                            301,852            296,563 
Preferred stock dividend requirements                                  53,020             56,108 
------------------------------------------------------------------------------------------------ 
                                                                                                 
EARNINGS FOR COMMON STOCK                                        $    248,832       $    240,455 
================================================================================================ 
                                                                                                 
AVERAGE COMMON SHARES OUTSTANDING (000)                               115,880            112,057 
------------------------------------------------------------------------------------------------ 
                                                                                                 
BASIC AND DILUTED EARNINGS PER COMMON SHARE                      $       2.15       $       2.15 
================================================================================================ 
                                                                                                 
Common stock dividends declared per share                        $       1.78       $       1.76 
Common stock dividends paid per share                            $       1.78       $       1.75 
Book value per common share at                                   $      20.21       $      19.88 
Common shares outstanding at (000)                                    118,417            112,332 
Common shareowners of record at                                        96,491             94,877 
=================================================================================================
                                                                                                 
TOTAL ASSETS                                                     $ 12,479,289       $ 12,453,771 
LONG-TERM DEBT                                                   $  5,145,397       $  4,870,340 
PREFERRED STOCK - REDEMPTION REQUIRED                            $    644,350       $    649,150 
PREFERRED STOCK - NO REDEMPTION REQUIRED                         $     63,957       $     64,038 
COMMON SHAREOWNERS' EQUITY                                       $  2,393,628       $  2,232,950 
</TABLE>

                                       32

<PAGE>

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

On April 11, 1997,  the Company  changed its year end from  December 31 to March
31.  Accordingly,  unless  otherwise  indicated,  references  to 1998  and  1997
represent  the twelve  month  periods  ended March 31, 1998 and March 31,  1997,
respectively,  while  references to all other  periods  refer to the  respective
calendar years ended December 31.

Effects of LIPA and KeySpan Transactions on Future Operations
The  future   operations   and  financial   position  of  the  Company  will  be
significantly  affected  by each of the  proposed  transactions  with  LIPA  and
KeySpan   described  below.  The  discussion   contained  in  this  management's
discussion  and analysis of financial  condition and results of operations  does
not  reflect,   unless  otherwise  indicated,   the  potential  effects  of  the
transactions with LIPA and KeySpan.


RESULTS OF OPERATIONS

EARNINGS
Earnings for the years ended March 31, 1998 and March 31, 1997 were as follows:

(In millions of dollars and shares except earnings per share)
--------------------------------------------------------------- -------------
                                                    1998            1997
--------------------------------------------------------------- -------------
Net income                                         $362.2          $322.4
Preferred stock dividend requirements                51.8            52.1
=============================================================== =============
Earnings for common stock                          $310.4          $270.3
=============================================================== =============
Average common shares outstanding                   121.4           120.6
=============================================================== =============
Basic and diluted earnings per common share       $   2.56        $   2.24
=============================================================== =============

For the year  ended  March 31,  1998 the  Company  had  higher  earnings  in the
electric  business  partially  offset  by  lower  earnings  in the gas  business
compared to the year ended March 31, 1997.

In the electric business,  the increase in earnings for the year ended March 31,
1998,  was  primarily  due to a change  in the  method  of  amortizing  the Rate
Moderation  Component  (RMC) to eliminate the effects of  seasonality on monthly
operating income, as more fully discussed in the section titled "Rate Moderation
Component."  This positive  contributor to earnings more than offset the effects
of lower short-term interest income and the accruals for certain obligations for
key  employees  , as more  fully  discussed  in  Note 8 of  Notes  to  Financial
Statements.

The  decrease in earnings in the gas  business for the year ended March 31, 1998
resulted from lower  short-term  interest income and the accruals,  noted above,
partially offset by lower operations and maintenance expenses.

Earnings for the years ended  December  31, 1996 and  December  31, 1995 were as
 follows: (In millions of dollars and shares except earnings per share)
--------------------------------------------- -------------- ---------------
                                                  1996            1995
--------------------------------------------- -------------- ---------------
Net income                                       $316.5          $303.3
Preferred stock dividend requirements              52.2            52.6
============================================= ============== ===============
Earnings for common stock                        $264.3          $250.7
============================================= ============== ===============
Average common shares outstanding                 120.4           119.2
============================================= ============== ===============
Basic and diluted earnings per common share      $  2.20         $  2.10
============================================= ============== ===============


                                       33

<PAGE>

The Company's 1996 earnings were higher for both its 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 were the result of
the Company's  increased  investment  in electric  plant in 1996, as compared to
1995. Also  contributing to the increase in electric  business earnings were 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 gas sales.

REVENUES

Electric Revenues

The table below provides a summary of the Company's electric revenues, sales and
customers.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
                                            Years Ended March 31,                Years Ended December 31,
-------------------------------------------------------------------------------------------------------------------
REVENUES (000)                             1998               1997                 1996               1995
-------------------------------------------------------------------------------------------------------------------
<S>                                      <C>              <C>                   <C>               <C>       
Residential                              $1,206,640       $1,199,976            $1,205,133        $1,204,987
Commercial and industrial                 1,194,725        1,178,471             1,174,499         1,194,014
Other system revenues                        47,832           50,499                50,513            52,472
-------------------------------------------------------------------------------------------------------------------
Total system revenues                     2,449,197        2,428,946             2,430,145         2,451,473
Other revenues                               29,238           36,011                36,290            32,541
================================================================================================-------------------
Total Revenues                           $2,478,435       $2,464,957            $2,466,435        $2,484,014
================================================================================================-------------------
SALES - MILLIONS OF KWH
Residential                                   7,170            7,121                 7,203             7,156
Commercial and industrial                     8,375            8,209                 8,242             8,336
Other system sales                              415              437                   441               460
================================================================================================-------------------
Total system sales                           15,960           15,767                15,886            15,952
================================================================================================-------------------
CUSTOMERS - MONTHLY AVERAGE
Residential                                 928,580          922,330               920,930           915,162
Commercial and industrial                   105,795          104,703               104,488           103,669
-------------------------------------------------------------------------------------------------------------------
</TABLE>


Years Ended March 31, 1998 and 1997

The Company's  electric revenues  fluctuate mainly 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  to eliminate  the impact on earnings  caused by sales
volumes  that are above or below  adjudicated  levels.  The slight  increase  in
revenues  for the year ended  March 31,  1998,  when  compared to the year ended
March 31, 1997,  was primarily  due to higher system sales volumes  resulting in
part from the addition of approximately  8,000 new electric customers and higher
fuel expense recoveries, partially offset by lower sales to other utilities.

Years Ended December 31, 1996 and 1995

The  Company  experienced  a  growth  in  electric  system  sales  in  1996 on a
weather-normalized basis compared to 1995. This growth is primarily attributable
to the addition of new electric customers.


                                       34

<PAGE>

For a further  discussion  on electric  rates,  see Note 4 of Notes to Financial
Statements.

Gas Revenues

The table below  provides a summary of the  Company's  gas  revenues,  sales and
customers.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------
                                                    Years Ended March 31,                  Years Ended December 31,
---------------------------------------------------------------------------------------------------------------------------
REVENUES (000)                                    1998                 1997                1996                1995
---------------------------------------------------------------------------------------------------------------------------
<S>                                             <C>                  <C>                 <C>                <C>     
Residential                                     $390,990             $396,143            $414,749           $365,775
Commercial and industrial                        145,861              163,824             181,356            165,257
---------------------------------------------------------------------------------------------------------------------------
Total firm revenues                              536,851              559,967             596,105            531,032
Interruptible revenues                            37,565               42,584              37,927             32,837
---------------------------------------------------------------------------------------------------------------------------
Total system revenues                            574,416              602,551             634,032            563,869
Other revenues                                    71,243               70,154              50,228             27,245
===========================================================================================================================
Total Revenues                                  $645,659             $672,705            $684,260           $591,114
===========================================================================================================================
SALES - THOUSANDS OF DTH
Residential                                       37,417               39,286              40,850             38,265
Commercial and industrial                         17,168               19,341              21,054             20,439
---------------------------------------------------------------------------------------------------------------------------
Total firm sales                                  54,585               58,627              61,904             58,704
Interruptible sales                                9,130                8,399               7,869              9,176
Off-system sales                                  10,372               10,036               7,457              7,743
---------------------------------------------------------------------------------------------------------------------------
Total Sales                                       74,087               77,062              77,230             75,623
========================================================================================================-------------------
CUSTOMERS - MONTHLY AVERAGE
Residential                                      415,369              411,734             410,922            407,566
Commercial and industrial                         44,917               45,684              45,887             45,340
---------------------------------------------------------------------------------------------------------------------------
Total firm customers                             460,286              457,418             456,809            452,906
Interruptible customers                              688                  659                 651                623
Firm transportation customers                      3,589                  833                 349                  -
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

Years Ended March 31, 1998 and 1997

Despite an increase of  approximately  5,600 gas space  heating  customers,  gas
revenues  decreased  primarily as a result of lower sales  volumes due to warmer
weather  experienced  during the year ended March 31, 1998 when  compared to the
year ended March 31, 1997.

In 1998 and 1997,  other gas  revenues  totaled  $71  million  and $70  million,
respectively.  Included  in other gas  revenues  is  off-system  gas sales which
totaled $34 million and $43 million,  for 1998 and 1997,  respectively.  Profits
generated from  off-system gas sales are allocated 85% to firm gas customers and
15% to the  shareowners,  in accordance with PSC mandates.  Off-system gas sales
decreased  as the demand for  natural  gas  declined  as a direct  result of the
warmer  weather  experienced  in this  region  during this  period.  

Years Ended December 31, 1996 and 1995

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,  higher sales
volumes,  an  increase in gas fuel  expense  recoveries  driven by higher  sales
volumes,  and revenues  generated through  non-traditional  services,  including
off-system gas sales. 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 1996 and 1995,  other gas 


                                       35
<PAGE>

revenues  totaled $50 million and $27 million,  respectively.  Included in other
gas revenues is  off-system  gas sales which totaled $37 million and $24 million
for 1996 and 1995, respectively.


OPERATING EXPENSES

Fuel and Purchased Power

Electric System

Fuel and purchased  power  expenses for the years ended March 31, 1998 and 1997,
and for the years ended December 31, 1996 and 1995 were as follows:

<TABLE>
<CAPTION>

                                                                                             (In millions of dollars)
-------------------------------------------------- ------------------------------- -----------------------------------
                                                           Years Ended                       Years Ended
                                                            March 31,                        December 31,
                                                            ---------                        ------------
                                                      1998             1997            1996              1995
-------------------------------------------------- --------------- --------------- --------------- -------------------
Fuel for Electric Operations
<S>                                                    <C>              <C>              <C>              <C> 
 Oil                                                   $123             $128             $158             $ 98
 Gas                                                    197              170              138              149
 Nuclear                                                 15               15               15               14
 Purchased power                                        324              333              329              310
================================================== =============== =============== =============== ===================
Total                                                  $659             $646             $640             $571
================================================== =============== =============== =============== ===================
</TABLE>

Variations in fuel and purchased power costs have no impact on operating results
as the Company's  current  electric  rate  structure  includes a mechanism  that
provides  for the  recovery  of fuel  costs  which  are  greater  than the costs
collected  in base  rates.  If the actual  fuel costs are less than the  amounts
included in base rates, the difference is credited to the RMC balance.

Electric  fuel and  purchased  power mix for the years  ended March 31, 1998 and
1997, and years ended December 31, 1996 and 1995 were as follows:

<TABLE>
<CAPTION>

                                                                                (In thousands of MWh)
---------------------------------------------------------------------------------------------------------------
                                            Years Ended                                 Years Ended
                                             March 31,                                 December 31,
                                             ---------                                 ------------
                                     1998                  1997                  1996                  1995
---------------------------------------------------------------------------------------------------------------
                                  MWh      %           MWh       %           MWh       %          MWh        % 
---------------------------------------------------------------------------------------------------------------
<S>                              <C>      <C>          <C>      <C>          <C>      <C>          <C>      <C>
Oil                              3,434    20%          3,278    19%          4,219    24%          3,099    17%
Gas                              6,212    35%          5,469    31%          4,542    25%          6,344    36%
Nuclear                          1,545     9%          1,553     9%          1,558     9%          1,301     7%
Purchased power                  6,412    36%          7,261    41%          7,388    42%          7,143    40%
---------------------------------------------------------------------------------------------------------------
Total                           17,603   100%         17,561   100%         17,707   100%         17,887   100%
===============================================================================================================
</TABLE>

In May 1997,  the Company  completed  the second 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 nine. As a result,  seven of the Company's nine steam  generating
units are currently  dual-fired,  providing the Company with the ability to burn
the most cost-efficient fuel available,  consistent with seasonal  environmental
requirements.

Years Ended March 31, 1998 and 1997

Electric fuel costs increased as a result of higher system sales volumes. During
1998, the price per kWh of power purchased increased over 1997. As a result, the
Company  changed the mix of generation and purchased power in 1998 when compared
to 1997 by generating more electricity  using gas and oil rather than purchasing
the equivalent energy from off-system.


                                       36

<PAGE>

Years Ended December 31, 1996 and 1995

As a result of a sharp  increase in the cost of natural gas in 1996,  generation
with oil became more  economical  than generation with gas. The total barrels of
oil consumed for  electric  operations  were 7.1 million and 5.2 million for the
years 1996 and 1995, respectively.

Gas System

Variations  in gas  fuel  costs  have no  impact  on  operating  results  as the
Company's  current gas rate structure  includes a fuel adjustment clause whereby
variations  between  actual fuel costs and fuel costs included in base rates are
deferred and  subsequently  returned to or collected from  customers.  Effective
February 5, 1998, in  accordance  with the  Stipulation,  discussed in Note 3 of
Notes to Financial  Statements,  total gas fuel costs are recovered  through the
gas fuel adjustment  clause.  

Years Ended March 31, 1998 and 1997

Gas system fuel  expense  totaled  $299  million and $309  million for the years
ended March 31, 1998 and 1997,  respectively.  The decrease is due to lower firm
sales  volumes and lower  off-system  gas sales  resulting  from warmer  weather
experienced in this region during this period.

Years Ended December 31, 1996 and 1995

For the years ended December 31, 1996 and 1995, gas system fuel expense  totaled
$323 million and $264 million, respectively. The increase of $59 million was due
to higher firm sales volumes,  an increase in the Company's average price of gas
and higher off-system gas sales.

Operations and Maintenance Expenses

Years Ended March 31, 1998 and 1997

Operations and Maintenance  (O&M) expenses,  excluding fuel and purchased power,
were $511 million and $490 million, for the years ended March 31, 1998 and 1997,
respectively.  This  increase in O&M was  primarily  due to the  recognition  of
higher  performance-based  employee  incentives  and certain  other  charges for
empoloyee benefits related to the KeySpan/LILCO merger.

Years Ended December 31, 1996 and 1995

O&M expenses,  excluding  fuel and purchased  power,  were $499 million and $511
million,  for the years ended  December  31, 1996 and 1995,  respectively.  This
decrease in O&M was  primarily  due to the Company's  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.  In addition,  the RMC is also adjusted
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.


                                       37

<PAGE>

In April  1998,  the PSC  authorized  a  revision  to the  Company's  method for
recording its monthly RMC amortization. Prior to this revision, the amortization
of the annual level of RMC was recorded  monthly on a  straight-line,  levelized
basis over the  Company's  rate year which runs from  December 1 to November 30.
However,   revenue  requirements  fluctuate  from  month  to  month  based  upon
consumption,  which is greatly  impacted by the  effects of weather.  Under this
revised  method,  effective  December 1, 1997, the monthly  amortization  of the
annual RMC level varies based upon each month's forecasted revenue requirements,
which more closely aligns such  amortization with the Company's cost of service.
As a result of this  change,  for the fiscal  year  ended  March 31,  1998,  the
Company  recorded  approximately  $65.1  million more of non-cash RMC credits to
income (representing accretion of the RMC balance), or $42.5 million net of tax,
representing  $.35 per  share  than it would  have  under the  previous  method.
However,  the total RMC  amortization for the rate year ended November 30, 1998,
will be equal to the amount that would have been provided for under the previous
method.

The Company  continues to believe that the full amortization and recovery of the
RMC balance,  which at March 31, 1998, was approximately $434 million, will take
place within the time frame established by the Rate Moderation  Agreement (RMA),
in accordance with the rate plans submitted to the Public Service  Commission of
the State of New York  (PSC) for the  single  rate year 1997 and the three  year
rate period 1997  through  1999.  In December  1997,  the Company  received  PSC
approval to continue the RMC mechanism and the LILCO  Ratemaking and Performance
Plan (LRPP)  ratemaking  mechanisms  and  incentives  for the electric rate year
ending  November  30,  1997.  In the  event  that  the LIPA  Transaction  is not
consummated, the Company expects that the PSC will issue an order providing for,
among other things, the continuing recovery,  through rates, of the RMC balance,
one of the Shoreham-related regulatory assets. If such an electric rate order is
not obtained or does not provide for the continuing recovery of the RMC balance,
the Company may be required to write-off  the amount not expected to be provided
for in rates. For a further  discussion of the LIPA  Transaction,  see Note 2 of
Notes to Financial Statements.

Years Ended March 31, 1998 and 1997

For the years  ended  March 31, 1998 and March 31,  1997,  the Company  recorded
non-cash  credits  to income  of  approximately  $52  million  and $30  million,
respectively,  representing  the amount by which revenue  requirements  exceeded
revenues  provided  for under the current  electric  rate  structure.  Partially
offsetting  these  accretions  were the  effects  of the FMC  mechanism  and the
differences  between  actual  and  adjudicated  operating  costs  for  NMP2,  as
discussed above. The adjustments to the accretion of the RMC totaled $17 million
and  $27  million,   respectively,   of  which  $12  million  and  $23  million,
respectively, were derived from the operation of the FMC mechanism.

Years Ended December 31, 1996 and 1995

For the year ended December 31, 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. The adjustments to the accretion of the RMC totaled $26 million,  of which
$24 million was derived from the operation of the FMC mechanism.


                                       38

<PAGE>

For the year ended December 31, 1995, the Company  recorded a non-cash charge to
income  of  approximately  $22  million,  after  giving  effect  to the  credits
generated  principally  by the operation of the FMC  mechanism.  FMC credits for
1995 totaled approximately $87 million.

For a  further  discussion  of  the  RMC,  see  Note  4 of  Notes  to  Financial
Statements.

Other Regulatory Amortization

The significant components of other regulatory amortization are the following:

<TABLE>
<CAPTION>
                                                                                           (In millions of dollars)
----------------------------------------- -------------------------------------------------------------------------
                                                                      (Income)Expense
----------------------------------------- -------------------------------------------------------------------------
                                                   Years Ended                               Years Ended
                                                    March 31                                 December 31
----------------------------------------- ------------- --------------- ------------ --------------- --------------
                                              1998            1997                         1996           1995
----------------------------------------- ------------- --------------- ------------ --------------- --------------
<S>                                            <C>           <C>                           <C>            <C> 
Net Margin                                     $ 2           $ (5)                         $  3           $ 64
LRPP Amortization                                -             42                            59             53
Excess Earnings - Electric                      (3)            21                            10              3
Excess Earnings - Gas                           10             10                            10              1
Shoreham Post Settlement Costs                  31             30                            29             27
Other                                            7             14                            16             14
========================================= ============= =============== ============ =============== ==============
                                               $47           $112                          $127           $162
========================================= ============= =============== ============ =============== ==============
</TABLE>

Net  Margin-  An  electric  business  unit  revenue  reconciliation   mechanism,
established  under  the  LRPP,  which  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  through  a charge  or  credit to other  regulatory
amortization.  These deferrals are then refunded to or recovered from ratepayers
as explained below under "LRPP Amortization."

LRPP  Amortization- As established under the LRPP,  deferred balances  resulting
from the net  margin,  electric  property  tax  expense  reconciliation,  earned
performance  incentives,  and associated carrying charges are accumulated during
each rate year. The first $15 million of the total deferral is recovered from or
credited to electric  ratepayers by  increasing  or decreasing  the RMC balance.
Amounts  deferred  in excess  of $15  million,  upon  approval  by the PSC,  are
refunded to or recovered from ratepayers  through the Fuel Cost Adjustment (FCA)
mechanism over a subsequent  12-month period,  with the offset being recorded in
other regulatory amortization.

For the rate years ended November 30, 1997 and 1996,  the total amount  deferred
under the LRPP was $4.0 and  $15.0  million,  respectively.  Such  amounts  were
credited against the RMC balance.

Years Ended March 31, 1998 and 1997

For the year  ended  March  31,  1998,  there was no LRPP  amortization,  as the
Company  has not yet  received  approval  from  the PSC to begin  refunding  $26
million of the remaining  deferred LRPP balance in excess of $15 million for the
rate year ended  November  30,  1995.  For the year ended  March 31,  1997,  the
Company recognized $42.4 million of non-cash charges to income  representing the
amortization  of the  deferred  LRPP  balance  related  to the rate  year  ended
November 30, 1994.


                                       39

<PAGE>

Years Ended December 31, 1996 and 1995

For the year ended  December 31, 1996, the Company  recognized  $58.7 million of
non-cash  charges to income  representing  the amortization of the deferred LRPP
balance related to the rate year ended November 30, 1994.

For the year ended  December 31, 1995, the Company  recognized  $52.9 million of
non-cash  charges to income  representing  the amortization of the deferred LRPP
balance related to the rate year ended November 30, 1993.

For a  further  discussion  of the  LRPP,  see  Note  4 of  Notes  to  Financial
Statements.

Excess Earnings - Also recorded in other regulatory amortization, if applicable,
are non-cash charges  representing:  (a) 100% of electric earnings  generated by
the  Company in excess of  amounts  provided  for in  electric  rates,  which is
returned to the electric  customer  through a reduction to the RMC balance;  and
(b) 50% of the gas  earnings  generated  by the  Company  in excess  of  amounts
provided  for in gas rates,  which will be  returned  to the firm gas  customer.
Effective  February 5, 1998,  the Company,  in accordance  with the  Stipulation
discussed  in  Note  3 of  Notes  to  Financial  Statements,  established  a gas
balancing account in order to defer excess gas earnings for future  disposition.
For the rate year ended  November 30, 1997,  the electric  business  earned $4.8
million  in excess of its  allowed  return  on  common  equity  and the firm gas
customers' portion of the gas business earnings was $6.3 million.

Shoreham  Post  Settlement  Costs -  Represents  the  amortization  of  Shoreham
decommissioning costs, fuel disposal costs, payments-in-lieu-of-taxes,  carrying
charges and other costs over a forty-year  period on a straight  line  remaining
life basis.

Years Ended March 31, 1998 and 1997

Other regulatory amortization was a non-cash charge to income of $47 million and
$112 million for the years ended March 31, 1998 and 1997, respectively.  For the
year ended March 31, 1997, the Company  recognized  approximately $42 million of
charges  representing the  amortization of the deferred LRPP balance  associated
with the rate year ended  November 30, 1994.  For the year ended March 31, 1998,
there was no LRPP  amortization,  as the Company has not yet  received  approval
from the PSC to begin  refunding  $26  million of the  remaining  deferred  LRPP
balance in excess of $15 million for the rate year ended November 30, 1995. Also
contributing to the decrease in other regulatory  amortization was the timing of
the  recognition of electric  excess  earnings for the rate years ended November
30, 1997 and 1996.


Years Ended December 31, 1996 and 1995

Other  regulatory  amortization was a non-cash charge to income of $127 and $162
for the years ended December 31, 1996 and 1995,  respectively.  This decrease is
primarily attributable to the operation of the net margin,  discussed above. For
the year ended December 31, 1995, the amount deferred  related to the net margin
amounted to $64 million  compared to $3 million for the year ended  December 31,
1996.


                                       40

<PAGE>

Operating Taxes

Operating taxes were $466 million and $470 million for the years ended March 31,
1998 and 1997,  respectively.  The decrease in 1998 is primarily attributable to
the  expiration of the Corporate  Tax Surcharge and lower gross  receipts  taxes
related to lower gas revenues.  For the years ended  December 31, 1996 and 1995,
operating taxes were $472 million and $448 million,  respectively.  The increase
in 1996  compared  to 1995 is  primarily  related to higher  property  taxes and
higher gross receipts taxes, due to increased revenues.

Federal Income Tax

Federal  income tax was $233  million and $211 million for the years ended March
31,  1998 and 1997,  respectively.  For the years  ended  December  31, 1996 and
December  31,  1995,  federal  income  tax was $209  million  and $206  million,
respectively.  The increase in federal income tax for both periods was primarily
attributable to higher pre-tax  earnings  partially offset by the utilization of
investment tax credits.

Other Income and Deductions, Net

Years Ended March 31, 1998 and 1997

Other  income and  deductions  was a $22  million  charge to income for the year
ended March 31,  1998,  compared to a $14 million  credit to income for the same
period in 1997.  The  difference,  which amounts to  approximately  $36 million,
relates  primarily  to a charge of  approximately  $31 million  with  respect to
certain  benefits  earned  by its  officers  recorded  in  1998.  For a  further
discussion of this matter, see Note 8 of Notes to Financial Statements.

Years Ended December 31, 1996 and 1995

Other income and deductions  totaled $19 million for the year ended December 31,
1996,  compared to $34 million for the same period in 1995. The decrease in 1996
when  compared  to  1995  is  primarily   attributable  to  the  recognition  of
non-recurring  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.

INTEREST EXPENSE

Years Ended March 31, 1998 and 1997

Interest expense for the year ended March 31, 1998 totaled $409 million compared
to $439  million for the year ended March 31, 1997.  This  decrease is primarily
attributable  to lower  outstanding  debt  levels as the  Company  retired  $250
million of G&R Bonds in February 1997.

Years Ended December 31, 1996 and 1995

Interest  expense for the year ended  December  31, 1996  totaled  $451  million
compared to $476 million for the year ended December 31, 1995.  This decrease 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.


                                       41

<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY

For the year ended March 31, 1998, 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 control both O&M expenses and construction expenditures;  (ii) lower interest
payments resulting from lower debt levels; and (iii) lower fuel expenditures.

At  March  31,  1998,  the  Company's  cash  and cash  equivalents  amounted  to
approximately  $181  million,  compared  to $65  million at March 31,  1997.  In
addition,  the Company  has  available  for its use a  revolving  line of credit
through October 1, 1998,  provided by its 1989 Revolving  Credit Agreement (1989
RCA). This line of credit is secured by a first lien upon the Company's accounts
receivable  and fuel oil  inventories.  In July 1997,  the Company  utilized $40
million in interim financing under the RCA, which was repaid in August 1997. The
Company  will, in order to satisfy  short-term  cash  requirements,  continue to
avail itself of interim financing  through the RCA, as necessary.  For a further
discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements.

The Company does not intend to access the financial  markets during 1998 to meet
any of its ongoing operating,  construction or refunding requirements.  However,
the Company will avail itself of any  tax-exempt  financing made available to it
by the New York State Energy Research and Development  Authority (NYSERDA).  The
Company used cash on hand to satisfy the retirement of $100 million of G&R Bonds
which matured on April 15, 1998.

In December  1997,  the Company  received $24.5 million in net proceeds from the
sale of  Electric  Facilities  Revenue  Bonds  (EFRBs)  issued by  NYSERDA.  The
proceeds from this  offering  were used to reimburse the Company's  treasury for
amounts previously expended on electric non-nuclear generation projects.

With respect to the  repayment of $454 million of maturing  debt and $22 million
of maturing preferred stock in 1999 and the repayment of $37 million of maturing
debt and $363  million  of  maturing  preferred  stock in 2000,  should the LIPA
Transaction not close, the Company intends to use cash generated from operations
to the maximum extent practicable.

Pursuant to the terms of the LIPA Transaction, each issued and outstanding share
of the Company's  preferred stock that is subject to optional redemption will be
called for  redemption at or before  closing of the LIPA  Transaction.  The LIPA
Transaction provides for repayment to the Company, at closing, for the principal
amount of the preferred  stock to be redeemed.  Accordingly,  on April 17, 1998,
the Company  exercised its option and called for redemption on May 19, 1998, all
the  outstanding  shares of its Preferred  Stock Series B, D, E, F, H, I, L, and
NN. The  redemption  of these  Preferred  Stock Series  amounted to $122 million
which included approximately $5 million of redemption premiums. The Company used
cash generated from operations and the utilization of interim  financing through
its 1989 RCA to finance the redemption. In the event the LIPA Transaction is not
consummated,  the Company may elect to access the capital  markets for permanent
financing to replace the Preferred Stock redeemed.

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. A settlement resolving all audit issues
was reached between the Company and the Internal Revenue


                                       42

<PAGE>

Service  in May 1998.  The  settlement  provided  for the  payment  of taxes and
interest of  approximately $9 million and $35 million,  respectively,  which the
Company made in May 1998.

In May 1998, the Company funded certain of its  obligations  for  postretirement
benefits  other than  pensions  in order to take a current  tax  deduction.  The
Company  secured a bridge  loan of $250  million  to fund  Voluntary  Employee's
Beneficiary  Association  trusts.  The Company intends to repay this bridge loan
upon the closing of the LIPA Transaction.

CAPITALIZATION

The Company's capitalization, including current maturities of long-term debt and
current  redemption  requirements of preferred stock, at March 31, 1998 and 1997
and December 31, 1996 and 1995, was $7.8 billion, $7.7 billion, $7.9 billion and
$8.3 billion, respectively.

At March 31, 1998 and 1997 and at,  December  31, 1996 and 1995,  the  Company's
capitalization ratios were as follows:
<TABLE>
<CAPTION>
--------------------------------------- --------------------------------- ----------------------------------
                                                    March 31                         December 31
--------------------------------------- --------------------------------- ----------------------------------
                                             1998              1997             1996             1995
--------------------------------------- ---------------- ----------------- ---------------- ----------------
<S>                                           <C>              <C>               <C>               <C>  
Long term debt                                57.3%            57.8%             59.3%             61.8%
Preferred stock                                9.0              9.1               8.9               8.6
Common shareowners' equity                    33.7             33.1              31.8              29.6
======================================= ================ ================= ================ ================
                                             100.0%           100.0%            100.0%            100.0%
======================================= ================ ================= ================ ================
</TABLE>

In support  of the  Company's  continuing  goal to reduce  its debt  ratio,  the
Company,  in February  1997,  retired at maturity $250 million of G&R Bonds with
cash on hand and by utilizing interim financing of $30 million, which was repaid
in March 1997.  The Company used cash on hand to satisfy the $100 million of G&R
Bonds which matured in April 1998.


INVESTMENT RATING

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

At March 31, 1998,  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*              Baa3*            BBB-*             BBB*
Debentures                                           BB+               Ba1              BB+               BB+
Preferred Stock                                      BB+               ba1              BB-               BB
------------------------------------------------------------------------------------------------------------------
Minimum Investment Grade                             BBB-*             Baa3*            BBB-*             BBB-*
==================================================================================================================
*Bold face indicates securities that meet or exceed minimum investment grade.
</TABLE>

During  March  1998,  following  the  announcement  that  the  Company  received
favorable tax rulings from the IRS with respect to the LIPA Transaction, Moody's
raised the ratings of the Company's  G&R Bonds to Baa3 from Ba1; its  debentures
to Ba1 from Ba3 and its preferred stock to ba1 from ba3.

During  October  1997,  S&P  announced  that it raised the  Company's  G&R Bonds
ratings one notch to BBB from BBB-. The upgrade resulted from S&P  incorporating
into its  ratings of  corporate  issues a more  vigorous  analysis  of  ultimate
recovery potential to supplement the analysis of default risk. The 


                                       43

<PAGE>

incorporation of ultimate recovery risk is particularly important for ratings of
electric,  gas, and water utility senior  secured debt. If, in S&P's  analytical
conclusion,  full recovery of principal  can be  anticipated  in a  post-default
scenario, an issue's rating may be enhanced above the corporate credit rating or
default rating.

CAPITAL REQUIREMENTS AND CAPITAL PROVIDED

Capital requirements and capital provided for the year ended March 31, 1998, the
three months ended March 31, 1997 and the year ended December 31, 1996,  were as
follows:
<TABLE>
<CAPTION>
                                                                                                   (In Millions of Dollars)
------------------------------------------------ -------------------------- ------------------------ ---------------------------
                                                        Year Ended           Three Months Ended             Year Ended
                                                      March 31, 1998           March 31, 1997            December 31, 1996
------------------------------------------------ -------------------------- ------------------------ ---------------------------
------------------------------------------------ -------------------------- ------------------------ ---------------------------
CAPITAL REQUIREMENTS
Construction *                                               $257                  $ 50                           $240
------------------------------------------------ -------------------------- ------------------------ ---------------------------
<S>                                                          <C>                   <C>                            <C>
Redemptions and Dividends
 Long-term debt                                                 1                   250                            415
 Preferred stock                                                1                     -                              5
 Preferred stock dividends                                     52                    13                             52
 Common stock dividends                                       216                    54                            214
------------------------------------------------ -------------------------- ------------------------ ---------------------------
Total Redemption and Dividends                                270                   317                            686
------------------------------------------------ -------------------------- ------------------------ ---------------------------
Shoreham post-settlement costs                                 40                    12                             52
Investment in interest rate hedge                              30                     -                              -
================================================ ========================== ======================== ===========================
Total Capital Requirements                                   $597                  $379                           $978
================================================ ========================== ======================== ===========================
CAPITAL PROVIDED
Cash from operations                                         $674                  $160                           $892
(Increase) Decrease in cash balances                         (116)                  215                             71
Long term debt issued                                          25                     -                              -
Common stock issued                                            18                     5                             19
Other investing and financing activities                      ( 4)                   (1)                           ( 4)
================================================ ========================== ======================== ===========================
Total Capital Provided                                       $597                  $379                           $978
================================================ ========================== ======================== ===========================
</TABLE>
* Excludes non-cash allowance for other funds used during construction.

For further information, see the Statement of Cash Flows.

For the year ended March 31, 1999, total capital requirements  (excluding common
stock  dividends)  are estimated to be $589 million,  of which  maturing debt is
$101  million,  construction  requirements  are $266  million,  preferred  stock
dividends are $45 million,  redemptions of preferred  stock are $144 million and
Shoreham  post-settlement  costs are $33  million  (including  $31  million  for
payments-in-lieu-of-taxes).  The  Company  believes  that  cash  generated  from
operations  coupled with cash  balances  will be  sufficient to meet all capital
requirements during this period.

OTHER MATTERS

LONG ISLAND POWER AUTHORITY TRANSACTION

For a discussion of the Long Island Power Authority  Transaction,  see Note 2 of
Notes to Financial Statements.

KEYSPAN ENERGY CORPORATION TRANSACTION

For a discussion of the KeySpan Energy  Corporation  Transaction,  see Note 3 of
Notes to Financial Statements.


                                       44

<PAGE>

RATE MATTERS

For a discussion of Rate Matters, see Note 4 of Notes to Financial Statements.

COMPETITIVE ENVIRONMENT

For a discussion of competitive issues facing the Company,  see Note 12 of Notes
to Financial Statements. 

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 (CERCLA, commonly known as Superfund), the federal Resource Conservation and
Recovery Act, the federal Toxic Substances Control Act (TSCA), the federal Clean
Water Act (CWA), and the federal Clean Air Act (CAA).

Capital expenditures for environmental improvements and related studies amounted
to  approximately  $9.2 million for the year ended March 31, 1998 and,  based on
existing  information,  are expected to be $4.0 million for the year ended March
31, 1999. The  expenditures in fiscal year 1998 and expected  spending in fiscal
year 1999 include a total of $10.6  million for the  completion  of a gas-firing
capability project at Northport Unit 1 and Port Jefferson Unit 4.

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  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 from its customers.

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).


                                       45

<PAGE>

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,  as 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  presently  applies the proceeds  resulting from any sales of excess
SO2 allowances as a reduction to the RMC balance.

The Company entered into a voluntary  Memorandum of  Understanding  with the DEC
which  provides  that the  Company  will not sell SO2  allowances  for use in 15
states in an effort to mitigate the transport of acid rain  precursors  into New
York State from upwind states.

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  rate of all the
utilities  in New York State for the years ended  December  31,  1997,  1996 and
1995.  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.
It is estimated that additional expenditures of approximately $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  $10 million to $34
million,  excluding  the Northport  Unit 1 conversion,  by the year 2003 to meet
Phase III NOx  reduction  requirements.  The  completion  of the  project to add
gas-firing capability at Northport Unit 1 (completed in May 1998 at a total cost
of  approximately  $8.4 million) will also  facilitate the Company's  compliance
with the anticipated Phase III Nox reduction requirements.

Continuous Emission Monitoring

Additional software and equipment upgrades for Continuous  Emissions Monitors of
approximately  $2  million  may be  required  through  1999  at  all  generating
facilities  in order  to meet EPA  requirements  under  development  for the NOx
allowance tracking/trading 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 


                                       46

<PAGE>

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 $1.5 million in fiscal 1998 and
the planned  spending of $0.5 million through March 31, 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  approximately  23%
since  1990,  largely  through  greater  reliance  on the use of natural gas and
through conservation programs.  This makes the Company less vulnerable to future
CO2 reduction requirements.

Opacity Issues

The DEC  has  proposed  commencing  enforcement  actions  against  all New  York
utilities  for  alleged  opacity  exceedences  from  steam  electric  generating
facilities. Opacity is a measure of the relative level of light that is obscured
from passing through a power plant stack emission  plume.  An exceedence  occurs
when the level of light  passing  through  the plume is reduced by more than 20%
for six minutes or more. The Company has entered into an Administrative  Consent
Order (ACO) with the DEC which  resolves  all  historical  opacity  exceedences,
establishes an opacity  reduction  program to be undertaken by the Company,  and
sets a  stipulated  penalty  schedule  for  future  exceedences.  The  number of
exceedences  experienced by the Company is relatively  low,  placing the Company
among the best performers in New York State.

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,  four  residential  property  owners  have
initiated  separate  lawsuits against the Company alleging that the existence of
EMF  has  diminished  the  value  of  their  homes.  These  actions  are  in the
preliminary  stages of  discovery  and are  similar to actions  brought  against
another New York State utility, which were dismissed by the New York State Court
of Appeals.  The Company is not involved in any active litigation that alleges a
causal relationship between exposure to EMF and adverse health effects.

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 


                                       47

<PAGE>

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 fiscal year 1998,  the Company  spent  approximately  $300,000 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  $100,000 in
the years 1998-2000.

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 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.

The Owners  have also  entered  into an ACO with the DEC as a result of leaks of
dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to
participate  in and  separately  approve the reports and studies being  prepared
pursuant  to the ACO issued by the DEP.  In  addition,  the ACO  settles any DEC
claim for natural  resource  damages in connection with  historical  releases of
dielectric fluid from the Sound Cable.

In October 1995, 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 December 1996, a barge,  owned and operated by a third party,  dropped anchor
which then dragged over and damaged the Sound Cable, resulting in the release of
dielectric fluid into Long Island Sound.  Temporary clamps and leak abaters were
installed on the cables to stop the leaks.  Permanent  repairs were completed in
June 1997. The cost to repair the Sound Cable was  approximately  $17.8 million,
for which there was $15 million of insurance coverage.  The Owners filed a claim
and answer in response to the maritime limitation  proceeding  instituted by the
barge owner in the United States District Court,  Eastern  District of New York.
The claim seeks recovery of the amounts paid by insurance  carriers and recovery
of the costs  incurred for which there was no insurance  coverage.  Any costs to
repair the Sound Cable which are 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.


                                       48

<PAGE>

In the course of the  Company's  ordinary  business  operations,  the Company is
involved in the handling of materials that are deemed to be hazardous substances
under Superfund. These materials include asbestos, metals, certain flammable and
organic  compounds and dielectric fluids  containing  polychlorinated  biphenyls
(PCBs). Other hazardous substances may be handled in the Company's operations or
may be present at Company  locations as a result of historical  practices by the
Company or its  predecessors  in  interest.  The  Company  has  received  notice
concerning possible claims under Superfund or analogous state laws relating to a
number of sites at which it is alleged that  hazardous  substances  generated by
the Company and other potentially  responsible parties (PRPs) were deposited.  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.  In January 1998,  the
Company  commenced a similar  action  against  the same and  certain  additional
insurer  defendants  in New York State  Supreme  Court,  First  Department;  the
federal court action was  subsequently  dismissed in March 1998.  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,  completed  performance of a Remedial
Investigation  and Feasibility  Study (RI/FS),  which was conducted under an ACO
with the EPA. In  December  1997,  the EPA issued its Record of Decision  (ROD),
setting forth the final remedial  action  selected for the site. In the ROD, the
EPA estimated that the present cost of the selected remedy for the site is $17.3
million. At this time, the Company cannot predict with reasonable  certainty the
actual cost of the selected remedy,  who will implement the remedy, or the cost,
if  any,  to the  Company.  Under a PRP  participation  agreement,  the  Company
previously was responsible for 8.2% of the costs  associated with the RI/FS. The
Company's  allocable share of liability for the  remediation  activities has not
yet been determined.

The Company has recorded a liability of  approximately  $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  


                                       49

<PAGE>

incurred  for a federal  Superfund  site in  Syosset,  New  York.  For a further
discussion on this matter, see Item 3, Legal Proceedings - Environmental.

PCB Treatment, 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
Treatment, 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.

Certain of the PRPs, including the Company and several other utilities, formed a
PRP  group,  signed an ACO,  and have  developed  a workplan  for  investigating
environmental  conditions at the sites.  Documentation connecting the Company to
the sites  indicates  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.

Osage

The EPA has  notified  the Company  that it is a PRP at the Osage Metals Site, a
former scrap metal  recycling  facility  located in Kansas City,  Kansas.  Under
Section  107(a) of CERCLA,  parties  who  arranged  for  disposal  of  hazardous
substances  are liable for costs  incurred by the EPA in responding to a release
or threat of release of the hazardous substances.  Osage had purchased capacitor
scrap metal from PCB Treatment,  Inc. Through the arrangements  that the Company
made with PCB Treatment,  Inc. to dispose of capacitors,  the Company is alleged
to have arranged for disposal within the meaning of the federal Superfund law. A
similar  letter was sent to 861 parties who sent  capacitors  to PCB  Treatment,
Inc.  The EPA is  seeking  to  recover  approximately  $1.1  million  dollars it
expended  to conduct a removal  action at the site.  The  Company  is  currently
unable to determine its share of the $1.1 million expenditure.

Port Refinery

The Company has been notified  that it is a PRP at the Port  Refinery  Superfund
site located in Westchester  County,  New York. Port Refinery was engaged in the
business of purchasing, selling, refining and processing mercury and the Company
may have shipped a small  amount of waste  products  containing  mercury to this
site.  Tests  conducted by the EPA indicated that the site and certain  adjacent
properties were contaminated with mercury.  As a result, the EPA has performed a
response action at the site and seeks to recover its costs,  currently  totaling
approximately $4.4 million,  plus interest,  from the PRPs. The Company does not
believe its portion of these costs, if any, will be material.

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 sent any materials to
the site that contributed to the  contamination  which requires  remediation and
has  therefore  declined  the EPA's  requests  to  participate  in  funding  the
investigation  and remediation  activities at the property.  The Company has not
received further communications regarding this site.


                                       50

<PAGE>

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

Huntington/East Northport

The DEC has notified the Company,  pursuant to the State Superfund program, that
its records indicate the Company may be responsible for the disposal of waste at
this  municipal  landfill  property.  The  Company  conducted  a  search  of its
corporate  records and did not locate any documents  concerning  waste  disposal
practices  associated  with this  landfill.  The Company is currently  unable to
determine its share,  if any, of the costs to  investigate  and  remediate  this
site.

Blydenburgh

The New York State Office of the Attorney  General has notified the Company that
it may be  responsible  for the disposal of wastes and/or for the  generation of
hazardous  substances  which  may  have  been  disposed  of at  the  Blydenburgh
Superfund  site,  a municipal  sanitary  landfill  located in the Town of Islip,
Suffolk County.  The State has incurred  approximately  $15 million in costs for
the investigation  and remediation of environmental  conditions at the landfill.
In  connection  with this  notification,  the Company  conducted a review of its
corporate  records and did not locate any documents  concerning  waste  disposal
practices  associated  with this  landfill.  The Company is currently  unable to
determine its share,  if any, of the costs to  investigate  and  remediate  this
site. 

Other Sites 

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 is expected to 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  preliminary
investigations  conducted at each of these six sites, current estimates indicate
that it may cost  approximately  $54 to $92 million to investigate and remediate
all of these sites. Considering the range of possible remediation estimates, the
Company felt it  appropriate  to record a $54 million  liability  reflecting the
present  value of the future  stream of  payments  amounting  to $70  million to
investigate and remediate these sites. The Company used a risk-free rate of 6.0%
to discount this obligation.  The Company believes that the PSC will provide for
future recovery of these costs and has recorded a $54 million  regulatory asset.
The  Company's  rate  settlement  which  the PSC  approved  February  4, 1998 as
discussed in Note 3 of Notes to Financial Statements, allows for the recovery of
MGP expenditures from gas customers.


                                       51

<PAGE>

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.

North Hills Leak

The Company has undertaken remediation of certain soil locations in North Hills,
New York that were impacted by a release of insulating  fluid from an electrical
cable in August 1994. The Company  estimates  that any additional  cleanup costs
will not exceed $0.5 million.  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.

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.  To the extent  that these costs are not
recoverable through insurance carriers,  the Company believes such costs will be
recoverable from its customers.

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 at least  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  


                                       52

<PAGE>

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 2012.

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

IMPACT OF YEAR 2000

Some of the  Company's  older  computer  programs  were written using two digits
rather than four to define the  applicable  year.  As a result,  those  computer
programs have  time-sensitive  software that recognizes a date using "00" as the
year 1900  rather  than the year  2000.  This  could  cause a system  failure or
miscalculations  causing  disruptions  of  operations,  including,  among  other
things,  a  temporary  inability  to process  transactions,  or engage in normal
business activities.

The Company  embarked on a program in 1996 to complete  Year 2000  compliance by
December 31, 1998. A  corporate-wide  program has been established to review all
software,  hardware and associated  compliance plans. The readiness of suppliers
and vendor systems is also under review.  Contingency and business  continuation
plans are being prepared and will be reviewed periodically.

The Company expects to spend  approximately $10 million to address the Year 2000
issue over a three-year period (1997-1999)  consisting of $7 million to test and
modify  application  systems  and $3 million to test and modify  non-information
technology  systems.  All costs will be  expensed as  incurred.  As of March 31,
1998, $4.53 million has been expended in investigating  and modifying  software.
This effort is scheduled to be completed in 1998 and testing will  continue into
early 1999. 

The  Company  believes  that,  with   modifications  to  existing  software  and
conversions  to new  software,  the Year 2000  Issue  will not pose  significant
operational  problems for its computer systems.  However,  if such modifications
and  conversions are not made, or are not completed on time, the Year 2000 Issue
could have a material adverse impact on the operations of the Company.

The costs of the  project  and the date on which the  Company  believes  it will
complete the Year 2000  modifications  are based on management's best estimates,
which were derived utilizing  numerous  assumptions of future events,  including
the continued  availability  of certain  resources and other  factors.  However,
actual results could differ materially from those anticipated.  Specific factors
that might cause such material  differences include, but are not limited to, the
availability  and cost of personnel  trained in this area, the ability to locate
and correct all relevant computer codes and similar uncertainties.

RECENT ACCOUNTING PRONOUNCEMENTS

Comprehensive Income

In June 1997, the Financial  Accounting  Standards Board (FASB) issued Statement
of  Financial  Accounting  Standards  (SFAS) No. 130.  SFAS No. 130  establishes
standards for reporting comprehensive income. Comprehensive income is the change
in the equity of a  company,  not  including  those  changes  that  result  from
shareholder transactions. All components of comprehensive income are required to
be reported in a new financial statement that is displayed with equal 


                                       53

<PAGE>

prominence  as existing  financial  statements.  The Company will be required to
adopt SFAS No. 130 for the year ending  March 31,  1999.  The  Company  does not
expect that the adoption of SFAS NO. 130 will have a  significant  impact on its
reporting and disclosure requirements.

Segment Disclosures

Also in June 1997, FASB issued SFAS No. 131. SFAS No. 131 establishes  standards
for  additional  disclosure  about  operating  segments  for  interim and annual
financial statements. More specifically, it requires financial information to be
disclosed  for  segments  whose  operating  results  are  reviewed  by the chief
decision maker for decisions on resource  allocation.  It also requires  related
disclosures  about products and services,  geographic areas and major customers.
The Company will be required to adopt SFAS No. 131 for the year ending March 31,
1999.  The Company does not expect that the adoption of SFAS No. 131 will have a
significant impact on its reporting and disclosure requirements.

CONSERVATION SERVICES

The Company's 1997 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,   provided   financing  for  energy   efficiency,   induced  market
transformation and improved the efficiency of LILCO facilities.  The Company was
successful  in meeting the PSC Energy  Penalty  Threshold  by  obtaining  energy
savings  of  approximately  24.4 GWh at a cost less than  that  provided  for in
electric rates.

In 1998,  the Company  plans to continue to follow the  aforementioned  strategy
while introducing  several new initiatives.  These include a program targeted at
increasing  the energy  efficiency of residences  of low income  customers,  the
introduction of a peak load curtailment  program constructed to help the Company
meet its peak supply side  requirements  and an  increased  emphasis on programs
that induce market transformation.  Overall, the 1998 Plan targets an annualized
energy savings of 18.6 GWh at a budget of $10.7 million.

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 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  transactions  with The KeySpan Energy  Corporation
and LIPA as discussed under the heading "KeySpan Energy Corporation Transaction"
and "Long Island Power Authority  Transaction" state and federal regulatory rate
proceedings,  competition,  and certain  environmental matters each as discussed
herein, in the Joint Proxy Statement/Prospectus filed June 30, 1997, or in other
reports filed by the Company with the Securities and Exchange Commission.


                                       54

<PAGE>

FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
Balance Sheet                                                                                     (In thousands of dollars)
---------------------------------------------------------------------------------------------------------------------------
Assets at                                                         March 31, 1998         March 31, 1997   December 31, 1996
---------------------------------------------------------------------------------------------------------------------------

UTILITY PLANT
<S>                                                                  <C>                  <C>                  <C>        
Electric                                                             $ 4,031,510          $ 3,900,264          $ 3,882,297
Gas                                                                    1,233,281            1,171,183            1,154,543
Common                                                                   290,221              263,267              260,268
Construction work in progress                                            118,808              108,850              112,184
Nuclear fuel in process and in reactor                                    18,119               15,503               15,454
--------------------------------------------------------------------------------------------------------------------------
                                                                       5,691,939            5,459,067            5,424,746
Less - Accumulated depreciation and amortization                       1,877,858            1,759,110            1,729,576
--------------------------------------------------------------------------------------------------------------------------
Total Net Utility Plant                                                3,814,081            3,699,957            3,695,170
--------------------------------------------------------------------------------------------------------------------------

REGULATORY ASSETS
Base financial component (less accumulated
amortization of $883,496, $782,525 and $757,282)                       3,155,334            3,256,305            3,281,548
Rate moderation component                                                434,004              409,512              402,213
Shoreham post-settlement costs                                         1,005,316              996,270              991,795
Shoreham nuclear fuel                                                     66,455               68,581               69,113
Unamortized cost of issuing securities                                   159,941              187,309              194,151
Postretirement benefits other than pensions                              340,109              357,668              360,842
Regulatory tax asset                                                   1,737,932            1,767,164            1,772,778
Other                                                                    192,763              200,137              199,879
--------------------------------------------------------------------------------------------------------------------------
Total Regulatory Assets                                                7,091,854            7,242,946            7,272,319
--------------------------------------------------------------------------------------------------------------------------

NONUTILITY PROPERTY AND OTHER INVESTMENTS                                 50,816               18,870               18,597
--------------------------------------------------------------------------------------------------------------------------

CURRENT ASSETS
Cash and cash equivalents                                                180,919               64,539              279,993
Special deposits                                                          95,790               37,631               38,266
Customer accounts receivable (less allowance
for doubtful accounts of $23,483, $23,675 and $25,000)                   297,889              305,436              255,801
Other accounts receivable                                                 43,744               42,946               65,764
Accrued unbilled revenues                                                124,464              141,389              169,712
Materials and supplies at average cost                                    54,883               55,454               55,789
Fuel oil at average cost                                                  32,142               49,703               53,941
Gas in storage at average cost                                            14,634               10,893               73,562
Deferred tax asset - net operating loss                                       --               93,349              145,205
Prepayments and other current assets                                      13,807                8,805                8,569
--------------------------------------------------------------------------------------------------------------------------
Total Current Assets                                                     858,272              810,145            1,146,602
--------------------------------------------------------------------------------------------------------------------------

DEFERRED CHARGES                                                          85,702               77,656               76,991
--------------------------------------------------------------------------------------------------------------------------

TOTAL ASSETS                                                         $11,900,725          $11,849,574          $12,209,679
==========================================================================================================================

See Notes to Financial Statements.


                                       55

<PAGE>

                                                                                                 (In thousands of dollars)
---------------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities at                                 March 31, 1998        March 31, 1997    December 31, 1996
---------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION
Long-term debt                                                     $  4,395,555           $  4,471,675        $  4,471,675
Unamortized discount on debt                                            (13,606)               (14,628)            (14,903)
--------------------------------------------------------------------------------------------------------------------------
                                                                      4,381,949              4,457,047           4,456,772
--------------------------------------------------------------------------------------------------------------------------

Preferred stock - redemption required                                   562,600                638,500             638,500
Preferred stock - no redemption required                                     --                 63,598              63,664
--------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock                                                   562,600                702,098             702,164
--------------------------------------------------------------------------------------------------------------------------

Common stock                                                            608,635                605,022             603,921
Premium on capital stock                                              1,146,425              1,131,576           1,127,971
Capital stock expense                                                   (47,501)               (48,915)            (49,330)
Retained earnings                                                       956,092                861,751             840,867
Treasury stock, at cost                                                  (1,204)                  (385)                (60)
--------------------------------------------------------------------------------------------------------------------------
Total Common Shareowners' Equity                                      2,662,447              2,549,049           2,523,369
--------------------------------------------------------------------------------------------------------------------------

Total Capitalization                                                  7,606,996              7,708,194           7,682,305
--------------------------------------------------------------------------------------------------------------------------
REGULATORY LIABILITIES
Regulatory liability component                                           99,199                178,558             198,398
1989 Settlement credits                                                  59,397                125,138             127,442
Regulatory tax liability                                                 78,913                100,377             102,887
Other                                                                   151,922                158,660             139,510
--------------------------------------------------------------------------------------------------------------------------
Total Regulatory Liabilities                                            389,431                562,733             568,237
--------------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current maturities of long-term debt                                    101,000                  1,000             251,000
Current redemption requirements of preferred stock                      139,374                  1,050               1,050
Accounts payable and accrued expenses                                   228,583                230,189             289,141
LRPP payable                                                             30,118                 40,499              40,499
Accrued taxes (including federal income
tax of $28,308, $49,262 and $25,884)                                     34,753                 51,157              63,640
Accrued interest                                                        146,607                143,983             160,615
Dividends payable                                                        58,748                 58,474              58,378
Class Settlement                                                         60,000                 58,333              55,833
Customer deposits                                                        28,627                 29,173              29,471
--------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities                                               827,810                613,858             949,627
--------------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS
Deferred federal income tax - net                                     2,539,364              2,420,443           2,442,606
Class Settlement                                                         46,940                 89,487              98,497
Other                                                                    22,529                 20,889              39,447
--------------------------------------------------------------------------------------------------------------------------
Total Deferred Credits                                                2,608,833              2,530,819           2,580,550
--------------------------------------------------------------------------------------------------------------------------
OPERATING RESERVES
Pensions and other postretirement benefits                              401,401                387,048             381,996
Claims and damages                                                       66,254                 46,922              46,964
--------------------------------------------------------------------------------------------------------------------------
Total Operating Reserves                                                467,655                433,970             428,960
--------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES                                                --                     --                  --
--------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES                               $ 11,900,725           $ 11,849,574        $ 12,209,679
 =========================================================================================================================
</TABLE>

See Notes to Financial Statements.


                                       56

<PAGE>

<TABLE>
<CAPTION>
STATEMENT OF INCOME                                                           (In thousands of dollars except per share amounts)
-------------------------------------------------------------------------------------------------------------------------------
                                                                           Three Months
                                                        Year Ended            Ended            Year Ended          Year Ended
                                                       March 31, 1998     March 31, 1997    December 31, 1996   December 31, 1995
-------------------------------------------------------------------------------------------------------------------------------
REVENUES
<S>                                                    <C>                  <C>                <C>                 <C>        
Electric                                               $ 2,478,435          $ 557,791          $ 2,466,435         $ 2,484,014
Gas                                                        645,659            293,391              684,260             591,114
-------------------------------------------------------------------------------------------------------------------------------
Total Revenues                                           3,124,094            851,182            3,150,695           3,075,128
-------------------------------------------------------------------------------------------------------------------------------

OPERATING EXPENSES
Operations - fuel and purchased power                      957,807            301,867              963,251             834,979
Operations - other                                         400,045             95,673              381,076             383,238
Maintenance                                                111,120             29,340              118,135             128,155
Depreciation and amortization                              158,537             38,561              153,925             145,357
Base financial component amortization                      100,971             25,243              100,971             100,971
Rate moderation component amortization                     (35,079)             5,907              (24,232)             21,933
Regulatory liability component amortization                (79,359)           (19,840)             (79,359)            (79,359)
1989 Settlement credits amortization                        (9,213)            (2,303)              (9,214)             (9,214)
Other regulatory amortization                               47,272             12,218              127,288             161,605
Operating taxes                                            466,326            117,513              472,076             447,507
Federal income tax - current                                86,388             23,378               42,197              14,596
Federal income tax - deferred and other                    150,983             33,624              168,000             193,742
-------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                 2,355,798            661,181            2,414,114           2,343,510
-------------------------------------------------------------------------------------------------------------------------------
Operating Income                                           768,296            190,001              736,581             731,618
-------------------------------------------------------------------------------------------------------------------------------

OTHER INCOME AND (DEDUCTIONS)
Rate moderation component carrying charges                  23,632              5,919               25,259              25,274
Other income and deductions, net                           (18,156)               645               19,197              34,400
Class Settlement                                           (15,623)            (4,496)             (20,772)            (21,669)
Allowance for other funds used during construction           3,846                717                2,888               2,898
Federal income tax - current                                   594                  -                    -                   -
Federal income tax - deferred and other                      4,124                789                  940               2,800
-------------------------------------------------------------------------------------------------------------------------------
Total Other Income and (Deductions)                         (1,583)             3,574               27,512              43,703
-------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges                             766,713            193,575              764,093             775,321
-------------------------------------------------------------------------------------------------------------------------------

INTEREST CHARGES
Interest on long-term debt                                 351,261             90,168              384,198             412,512
Other interest                                              57,805             16,659               67,130              63,461
Allowance for borrowed funds used during construction       (4,593)              (949)              (3,699)             (3,938)
-------------------------------------------------------------------------------------------------------------------------------
Total Interest Charges                                     404,473            105,878              447,629             472,035
-------------------------------------------------------------------------------------------------------------------------------

NET INCOME                                                 362,240             87,697              316,464             303,286
Preferred stock dividend requirements                       51,813             12,969               52,216              52,620
-------------------------------------------------------------------------------------------------------------------------------

EARNINGS FOR COMMON STOCK                                $ 310,427           $ 74,728            $ 264,248           $ 250,666
===============================================================================================================================

AVERAGE COMMON SHARES OUTSTANDING (000)                    121,415            120,995              120,360             119,195
-------------------------------------------------------------------------------------------------------------------------------

BASIC AND DILUTED EARNINGS PER COMMON SHARE              $    2.56           $   0.62            $    2.20           $    2.10
==================================================================================================================================

DIVIDENDS DECLARED PER COMMON SHARE                      $    1.78           $   0.45            $    1.78           $    1.78
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Financial Statements.


                                       57

<PAGE>

<TABLE>
<CAPTION>
STATEMENT OF CASH FLOWS
                                                                                               (In thousands of dollars)
------------------------------------------------------------------------------------------------------------------------
                                                                Year          Three          Year             Year
                                                                Ended       Months Ended     Ended            Ended
                                                              March 31      March 31      December 31      December 31
                                                                1998          1997           1996             1995
------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES

<S>                                                             <C>            <C>           <C>               <C>     
Net Income                                                      $362,240       $87,697       $316,464          $303,286
Adjustments to reconcile net income to net
      cash provided by operating activities
  Provision for doubtful accounts                                 23,239         4,821         23,119            17,751
  Depreciation and amortization                                  158,537        38,561        153,925           145,357
  Base financial component amortization                          100,971        25,243        100,971           100,971
  Rate moderation component amortization                         (35,079)        5,907        (24,232)           21,933
  Regulatory liability component amortization                    (79,359)      (19,840)       (79,359)          (79,359)
  1989 Settlement credits amortization                            (9,213)       (2,303)        (9,214)           (9,214)
  Other regulatory amortization                                   47,272        12,218        127,288           161,605
  Rate moderation component carrying charges                     (23,632)       (5,919)       (25,259)          (25,274)
  Class Settlement                                                15,623         4,496         20,772            21,669
  Amortization of cost of issuing and redeeming securities        30,823         8,087         34,611            39,589
  Federal income tax - deferred and other                        146,859        32,835        167,060           190,942
  Pensions and Other Post Retirement Benefits                     48,512        13,496         14,952             4,900
  Other                                                           87,618         2,381         51,671            56,675
Changes in operating assets and liabilities
  Accounts receivable                                            (14,905)      (31,638)        69,215           (67,213)
  Materials and supplies, fuel oil and gas in storage             14,391        67,242        (34,531)           21,986
  Accounts payable and accrued expenses                            1,668       (58,952)        28,258            19,100
  Class Settlement                                               (56,503)      (11,006)       (42,084)          (33,464)
  Special deposits                                               (58,159)          635         25,146           (35,798)
  Other                                                          (86,819)      (14,394)       (26,460)          (83,442)
------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities                        674,084       159,567        892,313           772,000
------------------------------------------------------------------------------------------------------------------------

INVESTING ACTIVITIES

Construction and nuclear fuel expenditures                      (257,402)      (50,375)      (239,896)         (243,586)
Shoreham post-settlement costs                                   (39,828)      (12,104)       (51,722)          (70,589)
Investment in interest rate hedge                                (30,000)          ---            ---               ---
Other                                                             (1,987)          160         (4,806)            8,019
------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities                           (329,217)      (62,319)      (296,424)         (306,156)
------------------------------------------------------------------------------------------------------------------------

FINANCING ACTIVITIES

Proceeds from issuance of securities                              43,218         4,640         18,837            68,726
Redemption of securities                                          (2,050)     (250,000)      (419,800)         (104,800)
Common stock dividends paid                                     (215,790)      (53,749)      (213,753)         (211,630)
Preferred stock dividends paid                                   (51,833)      (12,969)       (52,264)          (52,667)
Other                                                             (2,032)         (624)          (369)              529
------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities                           (228,487)     (312,702)      (667,349)         (299,842)
------------------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS            $116,380     ($215,454)      ($71,460)         $166,002
------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period                 $64,539      $279,993       $351,453          $185,451
Net increase (decrease) in cash and cash equivalents             116,380      (215,454)       (71,460)          166,002
------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD                      $180,919       $64,539       $279,993          $351,453
------------------------------------------------------------------------------------------------------------------------
Interest paid, before reduction for the allowance
    for borrowed funds used during construction                 $364,864      $112,981       $404,663          $427,988

Federal income tax paid                                         $108,980           ---        $45,050           $14,200
------------------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Financial Statements.


                                       58

<PAGE>

STATEMENT OF RETAINED EARNINGS
<TABLE>
<CAPTION>
                                                                                                (In thousands of dollars)
--------------------------------------------------------------------------------------------------------------------------------
                                                               March 31, 1998  March 31, 1997  December 31, 1996 December 31, 1995
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>               <C>             <C>             <C>         
Balance at beginning of period                                 $     861,751     $   840,867     $    790,919    $    752,480
Net income for the period                                            362,240          87,697          316,464         303,286
------------------------------------------------------------------------------------------------------------------------------
                                                                   1,223,991         928,564        1,107,383       1,055,766
Deductions
Cash dividends declared on common stock                              216,086          53,844          214,255         212,181
Cash dividends declared on preferred stock                            51,812          12,969           52,240          52,647
Other                                                                      1               -               21              19
------------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD                                       $     956,092     $   861,751     $    840,867    $    790,919
==============================================================================================================================
</TABLE>

See Notes to Financial Statements.

<TABLE>
<CAPTION>
STATEMENT OF CAPITALIZATION                              Shares Issued                                   (In thousands of dollars)
-----------------------------------------------------------------------------------------------------------------------------------
                                          March 31, 1998   March 31, 1997   December 31, 1996  March 31, 1998   March 31, 1997  
-----------------------------------------------------------------------------------------------------------------------------------
COMMON SHAREOWNERS' EQUITY
<S>                                        <C>             <C>              <C>             <C>              <C>             
Common stock, $5.00 par value              121,727,040     121,004,315      120,784,277     $   608,635      $   605,022     
Premium on capital stock                                                                      1,146,425        1,131,576     
Capital stock expense                                                                           (47,501)         (48,915)    
Retained earnings                                                                               956,092          861,751     
Treasury stock, at cost                         46,281          16,985            3,485          (1,204)            (385)    
-----------------------------------------------------------------------------------------------------------------------------
TOTAL COMMON SHAREOWNERS' EQUITY                                                              2,662,447        2,549,049     
-----------------------------------------------------------------------------------------------------------------------------
                                                                           
PREFERRED STOCK - REDEMPTION REQUIRED                                      
Par value $100 per share                                                   
      7.40% Series L                           150,500         161,000          161,000          15,050           16,100     
      7.66% Series CC                          570,000         570,000          570,000          57,000           57,000     
Less - Series called for redemption                                                              15,050            1,050     
-----------------------------------------------------------------------------------------------------------------------------
                                                                                                 57,000           72,050     
-----------------------------------------------------------------------------------------------------------------------------
Par value $25 per share                                                    
      7.95% Series AA                       14,520,000      14,520,000       14,520,000         363,000          363,000     
      $1.67 Series GG                          880,000         880,000          880,000          22,000           22,000     
      $1.95 Series NN                        1,554,000       1,554,000        1,554,000          38,850           38,850     
      7.05% Series QQ                        3,464,000       3,464,000        3,464,000          86,600           86,600     
      6.875% Series UU                       2,240,000       2,240,000        2,240,000          56,000           56,000     
Less - Series called for redemption                                                              38,850                -     
Less - Mandatory redemption of preferred stock                                                   22,000                -     
-----------------------------------------------------------------------------------------------------------------------------
                                                                                                505,600          566,450     
-----------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required                                                     562,600          638,500     
-----------------------------------------------------------------------------------------------------------------------------
                                                                           
PREFERRED STOCK - NO REDEMPTION REQUIRED                                   
Par value $100 per share                                                   
      5.00% Series B                           100,000         100,000          100,000          10,000           10,000     
      4.25% Series D                            70,000          70,000           70,000           7,000            7,000     
      4.35% Series E                           200,000         200,000          200,000          20,000           20,000     
      4.35% Series F                            50,000          50,000           50,000           5,000            5,000     
      5 1/8% Series H                          200,000         200,000          200,000          20,000           20,000     
      5 3/4% Series I -  Convertible            14,743          15,978           16,637           1,474            1,598     
Less - Series called for redemption                                                              63,474                -     
-----------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required                                                        -           63,598     
-----------------------------------------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK                                                                       $   562,600      $   702,098   
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>


STATEMENT OF CAPITALIZATION                         (In thousands of dollars)
-----------------------------------------------------------------------------
                                                      December 31, 1996
-----------------------------------------------------------------------------
                                              
COMMON SHAREOWNERS' EQUITY                    
Common stock, $5.00 par value                         $   603,921       
Premium on capital stock                                1,127,971       
Capital stock expense                                     (49,330)      
Retained earnings                                         840,867       
Treasury stock, at cost                                       (60)      
-----------------------------------------------------------------------------
TOTAL COMMON SHAREOWNERS' EQUITY                        2,523,369       
-----------------------------------------------------------------------------
                                                                        
PREFERRED STOCK - REDEMPTION REQUIRED                                   
Par value $100 per share                                                
      7.40% Series L                                       16,100       
      7.66% Series CC                                      57,000       
Less - Series called for redemption                         1,050       
-----------------------------------------------------------------------------
                                                           72,050       
-----------------------------------------------------------------------------
Par value $25 per share                                                 
      7.95% Series AA                                     363,000       
      $1.67 Series GG                                      22,000       
      $1.95 Series NN                                      38,850       
      7.05% Series QQ                                      86,600       
      6.875% Series UU                                     56,000       
Less - Series called for redemption                             -       
Less - Mandatory redemption of preferred stock                  -       
-----------------------------------------------------------------------------
                                                                        
                                                          566,450       
-----------------------------------------------------------------------------
Total Preferred Stock - Redemption Required               638,500       
-----------------------------------------------------------------------------
                                                                        
PREFERRED STOCK - NO REDEMPTION REQUIRED                                
Par value $100 per share                                                
      5.00% Series B                                       10,000       
      4.25% Series D                                        7,000       
      4.35% Series E                                       20,000       
      4.35% Series F                                        5,000       
      5 1/8% Series H                                      20,000       
      5 3/4% Series I -  Convertible                        1,664       
Less - Series called for redemption                             -       
-----------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required             63,664       
-----------------------------------------------------------------------------
TOTAL PREFERRED STOCK                                 $   702,164       
-----------------------------------------------------------------------------


                                       59

<PAGE>

<TABLE>
<CAPTION>
                                                                                                         (In thousands of dollars)
-----------------------------------------------------------------------------------------------------------------------------------
                                        Maturity          Interest Rate        Series             March 31, 1998     March 31, 1997
----------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                       <C>             <C>                 <C>               <C>      
GENERAL AND REFUNDING BONDS
                                     February 15, 1997         8 3/4%                              $          -      $         -   
                                        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                                                                      1,286,000        1,286,000  
----------------------------------------------------------------------------------------------------------------------------------
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                    27,375           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         3.58%           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         3.70%           1993 A                    50,000           50,000   
                                      November 1, 2023         3.70%           1993 B                    50,000           50,000   
                                       October 1, 2024         3.70%           1994 A                    50,000           50,000   
                                        August 1, 2025         3.70%           1995 A                    50,000           50,000   
                                      December 1, 2027         3.55%           1997 A                    24,880                -   
----------------------------------------------------------------------------------------------------------------------------------
Total Authority Financing Notes                                                                         940,555          916,675   
----------------------------------------------------------------------------------------------------------------------------------
Unamortized Discount on Debt                                                                            (13,606)         (14,628)  
----------------------------------------------------------------------------------------------------------------------------------
Total                                                                                                 4,482,949        4,458,047   
Less Current Maturities                                                                                 101,000            1,000   
----------------------------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT                                                                                  4,381,949        4,457,047   
----------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION                                                                               $  7,606,996      $ 7,708,194   
==================================================================================================================================
</TABLE>

<PAGE>


                                 (In thousands of dollars) 
                                     December 31, 1996 
-----------------------------------------------------------
                  
GENERAL AND REFUNDING BONDS
                                       $   250,000   
                                           100,000   
                                            56,000   
                                           185,000   
                                            75,000   
                                            80,000   
                                           415,000   
                                           375,000   
-----------------------------------------------------------
Total General and Refunding Bonds        1,536,000   
-----------------------------------------------------------
DEBENTURES                                           
                                           397,000   
                                            36,000   
                                           145,000   
                                           150,000   
                                            59,000   
                                           200,000   
                                           142,000   
                                           420,000   
                                           451,000   
                                           270,000   
-----------------------------------------------------------
Total Debentures                         2,270,000   
-----------------------------------------------------------
AUTHORITY FINANCING NOTES                            
Industrial Development Revenue Bonds                 
                                             2,000   
Pollution Control Revenue Bonds                      
                                            28,375   
                                            19,100   
                                            17,200   
                                           150,000   
                                                     
Electric Facilities Revenue Bonds          100,000   
                                           100,000   
                                           100,000   
                                           100,000   
                                           100,000   
                                            50,000   
                                            50,000   
                                            50,000   
                                            50,000   
                                                 -   
                                       
-----------------------------------------------------------
Total Authority Financing Notes            916,675     
-----------------------------------------------------------
Unamortized Discount on Debt               (14,903)    
-----------------------------------------------------------
Total                                    4,707,772     
Less Current Maturities                    251,000     
-----------------------------------------------------------
TOTAL LONG-TERM DEBT                     4,456,772     
-----------------------------------------------------------
TOTAL CAPITALIZATION                   $ 7,682,305     
===========================================================
See Notes to Financial Statements.


                                       60

<PAGE>

NOTES TO FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

On April 11, 1997,  the Company  changed its year end from  December 31 to March
31.  Accordingly,  unless  otherwise  indicated,  references  to 1998  and  1997
represent the twelve month period ended March 31, 1998 and March 31, 1997, while
references  to all other periods refer to the  respective  calendar  years ended
December 31.

As further  discussed  in Note 2, on June 26,  1997,  the  Company  and the Long
Island Power  Authority  (LIPA) entered into definitive  agreements  pursuant to
which, after the transfer of the Company's gas business unit assets, non-nuclear
electric  generating facility assets and certain other assets and liabilities to
one or more  newly-formed  subsidiaries of a new holding company,  the Company's
common stock will be sold to LIPA for approximately  $2.4975 billion in cash. No
adjustments have been made to the Company's financial statements to reflect this
proposed transaction.

Nature of Operations

The Company was incorporated in 1910 under the  Transportation  Corporations Law
of the State of New York and  supplies  electric  and gas  service in Nassau and
Suffolk  Counties and to the Rockaway  Peninsula in Queens  County,  all on Long
Island,   New  York.  The  Company's   service   territory  covers  an  area  of
approximately 1,230 square miles. The population of the service area,  according
to the Company's  1998 Long Island  Population  Survey  estimate,  is about 2.75
million  persons,  including  approximately  98,500 persons who reside in Queens
County within the City of New York.

The Company  serves  approximately  1.04  million  electric  customers  of which
approximately 931,000 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  467,000 gas customers,  417,000 of which
are residential,  accounting for about 61% of its gas revenues,  17,000 of which
are  commercial/industrial,  accounting  for 23% of its gas  revenues,  3,600 of
which are firm transportation customers,  accounting for 3% of its gas revenues,
with the balance of the gas revenues made up by 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 12.

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


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these commissions in conformity with generally  accepted  accounting  principles
for rate-regulated enterprises.

Accounting for the Effects of Rate Regulation

General

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

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 at March 31,  1998,  March 31, 1997 and December 31,
1996.

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.  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.  If the Company had been unable to continue to apply
the  provisions  of SFAS 71 at March  31,  1998,  the  Company  would  apply the
provisions   of  SFAS  101   "Regulated   Enterprises   -  Accounting   for  the
Discontinuation  of  Application  of FASB  Statement  No.  71". If SFAS 101 were
implemented,  the charge to earnings  could be as high as $4.5  billion,  net of
tax.  For  additional  information  respecting  the  Company's  Shoreham-related
assets, see below and Notes 4 and 10.

SFAS No.  121,  "Accounting  for the  Impairment  of  Long-Lived  Assets and for
Long-Lived  Assets to be Disposed Of" requires that 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


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the restoration of previously  disallowed costs that are subsequently allowed by
a  regulator.  No  impairment  losses have been  recognized  by the Company with
respect to regulatory or other long-lived assets.

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 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.

In April  1998,  the PSC  authorized  a  revision  to the  Company's  method for
recording its monthly RMC amortization. Prior to this revision, the amortization
of the annual level of RMC was recorded  monthly on a  straight-line,  levelized
basis over the  Company's  rate year which runs from  December 1 to November 30.
However,   revenue  requirements  fluctuate  from  month  to  month  based  upon
consumption,  which is greatly  impacted by the  effects of weather.  Under this
revised  method,  effective  December 1, 1997, the monthly  amortization  of the
annual RMC level varies based upon each month's forecasted revenue requirements,
which more closely aligns such  amortization with the Company's cost of service.
As a result of this  change,  for the fiscal  year  ended  March 31,  1998,  the
Company  recorded  approximately  $65.1  million more of non-cash RMC credits to
income (representing accretion of the RMC balance), or $42.5 million net of tax,
representing  $.35 per  share  than it would  have  under the  previous  method.
However,  the total RMC amortization for the rate year ending November 30, 1998,
will be equal to the amount that would have been provided for under the previous
method.  As discussed in Note 2, the RMC will be acquired by LIPA as part of the
LIPA Transaction.

For a further discussion of the 1989 Settlement and FRA, see Notes 4 and 10.

Shoreham Post-Settlement Costs

Shoreham  post-settlement costs consist 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 10.

Shoreham Nuclear Fuel

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


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Unamortized Cost of Issuing Securities

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, as
provided by the PSC,  over the shorter of the life of the redeemed  issue or the
new issue.

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 was phased  into and fully  reflected  in rates by
November 30, 1997, with the accumulated  deferred asset to be recovered in rates
over the  fifteen-year  period  which  began  December  1,  1997.  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   customers  and
shareowners.  A regulatory  liability of approximately $794 million was recorded
in June 1989 to preserve  an amount  equivalent  to the  customer  tax  benefits
attributable to the Shoreham abandonment.  This amount is being amortized over a
ten-year period on a straight-line basis which began July 1, 1989.

1989 Settlement Credits

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.


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Allowance for Funds Used During Construction

The Uniform Systems of Accounts as prescribed by the PSC,  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 AFC rate,  without giving effect to  compounding,  was as
follows:
                         Periods              AFC Rate
                 ------------------------     --------
                 12 Months Ended  3/31/98      9.29%
                  3 Months Ended  3/31/97      2.26%
                 12 Months Ended 12/31/96      9.02%
                 12 Months Ended 12/31/95      9.36%

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.  The average depreciation rate as a percentage of respective average
depreciable plant costs was as follows:

               Periods                     Electric        Gas
               -------                     --------        --- 
       12 Months Ended 3/31/98               3.07%        2.04%
        3 Months Ended 3/31/97                .78%         .51%
       12 Months Ended 12/31/96              3.00%        2.00%
       12 Months Ended 12/31/95              3.00%        2.00%

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 Payable

Represents the current portion of amounts due to 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 4.

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  based upon the  Company's  current  incremental
borrowing rate for similar types of securities.

Revenues

Revenues are comprised of cycle  billings  rendered to customers and the accrual
of electric and gas revenues  for services  rendered to customers  not billed at
month-end.

The Company's  electric  rate  structure  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.


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<PAGE>

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.  Pursuant to the  Stipulation,  as described in Note 3, gas fuel costs
are excluded from base fuel costs and recovered  through the gas fuel adjustment
clause.

Federal Income Tax

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

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

For ratemaking  purposes,  the Company provides deferred federal income tax with
respect to certain  differences  between  income before income tax 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.

Recent Accounting Pronouncements

Earnings Per Share
At December 31, 1997,  the Company  adopted SFAS No. 128,  "Earnings Per Share."
This statement  replaced the  calculation of primary and fully diluted  earnings
per share with basic and diluted earnings per share. Unlike primary earnings per
share,  basic  earnings  per share  excludes  any  dilutive  effects of options,
warrants and convertible securities. Diluted earnings per share are very similar
to the  previously  reported  fully  diluted  earnings  per  share.  None of the
earnings per share amounts for periods  presented  were effected by the adoption
of SFAS No. 128.

Comprehensive Income
In June 1997, the Financial  Accounting  Standards Board (FASB) issued Statement
of  Financial  Accounting  Standards  (SFAS) No. 130.  SFAS No. 130  establishes
standards for reporting comprehensive income. Comprehensive income is the change
in the equity of a  company,  not  including  those  changes  that  result  from
shareholder transactions. All components of comprehensive income are required to
be reported in a new financial statement that is displayed with equal prominence
as existing financial statements. The Company will be required to adopt SFAS No.
130 for the year ending  March 31,  1999.


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The  Company  does not  expect  that the  adoption  of SFAS No.  130 will have a
significant impact on its reporting and disclosure requirements.

Segment Disclosures

In June  1997,  FASB  issued  SFAS No. 131  "Disclosures  about  Segments  of an
Enterprise  and Related  Information."  SFAS No. 131  establishes  standards for
additional  disclosure about operating segments for interim and annual financial
statements. More specifically, it requires financial information to be disclosed
for  segments  whose  operating  results  are  reviewed  by the chief  operating
decision maker for decisions on resource  allocation.  It also requires  related
disclosures  about products and services,  geographic areas and major customers.
The  Company  will be  required to adopt SFAS No. 131 for the fiscal year ending
March 31,  1999.  The Company  does not expect that the adoption of SFAS No. 131
will have a significant impact on its reporting and disclosure requirements.

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.  Long Island Power Authority Transaction

On June 26, 1997,  the Company and Long Island Power  Authority  (LIPA)  entered
into  definitive  agreements  pursuant  to  which,  after  the  transfer  of the
Company's gas business unit assets,  non-nuclear  electric  generating  facility
assets and certain  other  assets and  liabilities  to one or more  newly-formed
subsidiaries  of a new holding company  (HoldCo),  formed in connection with the
LIPA Transaction and KeySpan  Transaction  discussed below, the Company's common
stock will be sold to LIPA for $2.4975 billion in cash.

In connection with this transaction, the principal assets to be acquired by LIPA
through  its  stock  acquisition  of LILCO  include:  (i) the net book  value of
LILCO's  electric  transmission  and  distribution  system,  which  amounted  to
approximately  $1.3 billion at March 31, 1998;  (ii) LILCO's net  investment  in
NMP2,  which amounted to  approximately  $0.7 billion at March 31, 1998 (as more
fully  discussed  in  Note  5);  (iii)  certain  of  LILCO's  regulatory  assets
associated with its electric business;  and (iv) allocated  accounts  receivable
and other  assets.  The  regulatory  assets to be acquired  by LIPA  amounted to
approximately  $6.6 billion at March 31, 1998, and primarily consist of the Base
Financial   Component  (BFC),   Rate  Moderation   Component   (RMC),   Shoreham
post-settlement  costs,  Shoreham  nuclear fuel, and the electric portion of the
regulatory tax asset. For a further  discussion of these regulatory  assets, see
Note 1.

LIPA is  contractually  responsible  for reimbursing  HoldCo for  postretirement
benefits  other than pension  costs  related to  employees  of LILCO's  electric
business.  Accordingly,  upon  consummation  of  the  transaction,  HoldCo  will
reclassify the associated  regulatory  asset for  postretirement  benefits other
than pensions to a contractual receivable.

The principal liabilities to be assumed by LIPA through its stock acquisition of
LILCO include: (i) LILCO's regulatory  liabilities  associated with its electric
business;  (ii) allocated accounts payable,  customer  deposits,  other deferred
credits and claims and damages;  and (iii) certain  series of long-term


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debt. The regulatory liabilities to be assumed by LIPA amounted to approximately
$365  million  at March  31,  1998,  and  primarily  consist  of the  regulatory
liability  component,  1989 Settlement  credits and the electric  portion of the
regulatory  tax  liability.   For  a  further  discussion  of  these  regulatory
liabilities, see Note 1 of Notes to Financial Statements.

The  long-term  debt to be assumed by LIPA will consist of: (i) all amounts then
outstanding under the General and Refunding (G&R)  Indentures;  (ii) all amounts
then  outstanding  under the Debenture  Indentures,  except as noted below;  and
(iii)  substantially all of the tax-exempt  authority financing notes. HoldCo is
required to assume the financial obligation associated with the 7.30% Debentures
due July 15, 1999, with an aggregate  principal amount currently  outstanding of
$397  million  and  8.20%  Debentures  due  March 15,  2023,  with an  aggregate
principal  amount  currently  outstanding  of $270 million.  HoldCo will seek to
exchange  its  Debentures,  with  identical  terms,  for  these  two  series  of
Debentures  and will issue a  promissory  note to LIPA in an amount equal to the
unexchanged amount of such Debentures.  HoldCo will also issue a promissory note
to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current
gas operations, with terms identical to those currently outstanding. The Company
currently  estimates the amount of this promissory note to be approximately $250
million.

In July 1997, in accordance  with the  provisions of the LIPA  Transaction,  the
Company and The Brooklyn  Union Gas Company  (Brooklyn  Union)  formed a limited
partnership  and each  Company  invested  $30  million in order to  purchase  an
interest  rate swap  option  instrument  to protect  LIPA  against  market  risk
associated with the municipal bonds expected to be issued by LIPA to finance the
transaction. Upon the closing of the LIPA Transaction, each limited partner will
receive from LIPA $30 million plus  interest  thereon,  based on each  partners'
average weighted cost of capital.  In the event that the LIPA Transaction is not
consummated,  the maximum potential loss to the Company is the amount originally
invested.  In such event,  the Company  plans to defer any loss and petition the
PSC to allow recovery from its customers.

As part of the LIPA Transaction,  the definitive agreements contemplate that one
or more subsidiaries of HoldCo will enter into agreements with LIPA, pursuant to
which such subsidiaries will provide management and operations  services to LIPA
with respect to the electric transmission and distribution system, deliver power
generated  by its power  plants to LIPA,  and manage  LIPA's  fuel and  electric
purchases and any off-system electric sales. In addition,  three years after the
LIPA Transaction is consummated,  LIPA will have the right for a one-year period
to acquire all of  HoldCo's  generating  assets at the fair market  value at the
time of the exercise of the right, which value will be determined by independent
appraisers.

In July 1997,  the New York  State  Public  Authorities  Control  Board  (PACB),
created pursuant to the New York State Public  Authorities Law and consisting of
five members  appointed by the  governor,  unanimously  approved the  definitive
agreements related to the LIPA Transaction subject to the following  conditions:
(i)  within  one  year of the  effective  date  of the  transaction,  LIPA  must
establish a plan for open access to the electric  distribution  system;  (ii) if
LIPA  exercises  its  option  to  acquire  the  generation  assets  of  HoldCo's
generation  subsidiary,  LIPA may not purchase  the  generating  facilities,  as
contemplated in the generation purchase right agreement, at a price greater than
book value; (iii) HoldCo must agree to invest,  over a ten-year period, at least
$1.3 billion in energy-related and economic  development  projects,  and natural
gas infrastructure  projects on Long Island; (iv) LIPA will guarantee that, over
a ten-year  period,  average  electric rates will be reduced by no less than 14%
when  measured  against  the  Company's  rates  today and no less than a 2% cost
savings to LIPA  customers  must  result from the  savings  attributable  to the
merger of LILCO and  KeySpan;  and (v) LIPA will not increase  average  electric
customer rates by more than


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2.5% over a twelve-month  period without approval from the PSC. LIPA has adopted
the conditions set forth by the PACB.

The  holders of common and  certain  series of  preferred  stock of the  Company
eligible to vote approved the LIPA Transaction in August 1997.

In December 1997, the United States Nuclear  Regulatory  Commission (NRC) issued
an order  approving  the  indirect  transfer  of  control of the  Company's  18%
ownership interest in NMP2 to LIPA.

In December 1997, the Company filed with the FERC a settlement agreement reached
with LIPA in connection with a previous  filing of the Company's  proposed rates
for the sale of  capacity  and  energy  to  LIPA,  as  contemplated  in the LIPA
transaction  agreements.  The Company also had  previously  filed an application
with the  FERC  seeking  approval  of the  transfer  of the  Company's  electric
transmission and distribution  system to LIPA in connection with LIPA's purchase
of the common stock of the Company.

In  February  1998,  the FERC  issued  orders  on both of the  Company  filings.
Specifically,  the FERC approved the Company's application to transfer assets to
LIPA in connection  with LIPA's  acquisition of the Company's  common stock.  In
addition,  the FERC accepted the Company's  proposed  rates for sale of capacity
and energy to LIPA.  Those  rates may go into  effect on the date the service to
LIPA begins,  subject to refund,  and final rates will be set after the FERC has
completed  its  investigation  of such  rates,  the  timing  of which  cannot be
determined at this time.

In January  1998,  the Company filed an  application  with the PSC in connection
with  the  proposed  transfer  of its  gas  business  unit  assets,  non-nuclear
generating  facility assets and certain other assets and related  liabilities to
one or more  subsidiaries  of HoldCo to be  formed as  contemplated  in the LIPA
Transaction agreements.  On April 29, 1998, the PSC approved the transfer of the
above-mentioned assets.

In July 1997,  the Company,  Brooklyn  Union and LIPA filed requests for private
letter rulings with the Internal Revenue Service (IRS) regarding certain federal
income  tax  issues  which  require  favorable  rulings  in  order  for the LIPA
Transaction to be consummated. On March 4, 1998, the IRS issued a private letter
ruling  confirming that the sale of the Company's common stock to LIPA would not
result in a corporate tax liability to the Company.  In addition,  the IRS ruled
that,  after the stock sale, the income of LIPA's electric utility business will
not be subject to federal income tax. In a separate ruling on February 27, 1998,
the IRS  also  ruled  that  the  bonds  to be  issued  by LIPA  to  finance  the
acquisition would be tax-exempt.

In January  1998,  the  Company  filed an  application  with the SEC  seeking an
exception for most of the provisions of the Public Utilities Holding Company Act
of  1935.  In May  1998,  the  SEC  issued  an  order  approving  the  Company's
application.

The Company currently  anticipates that the LIPA transaction will be consummated
by June 30, 1998.

Note 3.  KeySpan Energy Corporation Transaction

On December 29, 1996,  The Brooklyn Union Gas Company  (Brooklyn  Union) and the
Company  entered  into an  Agreement  and Plan of  Exchange  and  Merger  (Share
Exchange  Agreement),  pursuant  to which  the  companies  will be  merged  in a
transaction (KeySpan Transaction) that will result in the formation of HoldCo.

The Share  Exchange  Agreement  was  amended  and  restated  to reflect  certain
technical changes as of February 7, 1997 and June 26, 1997.  Effective September
29, 1997,  Brooklyn Union  reorganized  into a


                                       69

<PAGE>

holding company structure,  with KeySpan Energy  Corporation  (KeySpan) becoming
its parent holding company.  Accordingly, the parties entered into an Amendment,
Assignment and Assumption Agreement, dated as of September 29, 1997, which among
other  things,  amended the Share  Exchange  Agreement  and related stock option
agreements  to reflect  the  assignment  by  Brooklyn  Union to KeySpan  and the
assumption by KeySpan of all Brooklyn Union's rights and obligations  under such
agreements.

The KeySpan  Transaction,  which has been approved by both companies'  boards of
directors  and  shareholders,  would unite the resources of the Company with the
resources of KeySpan.  KeySpan, 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.  KeySpan  has  energy-related
investments  in gas  exploration,  production and marketing in the United States
and Northern Ireland, as well as energy services in the United States, including
cogeneration projects, pipeline transportation and gas storage.

Under the terms of the KeySpan  Transaction,  the Company's  common  shareowners
will receive .803 shares (the Ratio) of HoldCo's  common stock for each share of
the Company's common stock that they currently hold.  KeySpan common shareowners
will  receive  one share of  common  stock of HoldCo  for each  common  share of
KeySpan they currently hold.  Shareowners of the Company will own  approximately
66%  of  the  common  stock  of  HoldCo  while  KeySpan   shareowners  will  own
approximately  34%. In the event that the LIPA  Transaction is consummated,  the
Ratio will be 0.880 with Company  shareowners  owning  approximately  68% of the
HoldCo common stock.  Based on current facts and  circumstances,  it is probable
that the purchase  method of accounting  will apply to the KeySpan  Transaction,
with the Company being the acquiring company for accounting purposes.

Consummation  of the  Share  Exchange  Agreement  is not  conditioned  upon  the
consummation of the LIPA Transaction and consummation of the LIPA Transaction is
not conditioned upon consummation of the Share Exchange Agreement.

In March 1997, the Company filed an application  with the FERC seeking  approval
of the transfer of the Company's  common equity and certain  FERC-jurisdictional
assets to HoldCo. On July 17, 1997, the FERC granted such approval.

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.

Upon completion of the merger,  Dr. William J.  Catacosinos will become chairman
and chief executive officer of HoldCo; Mr. Robert B. Catell,  currently chairman
and  chief  executive  officer  of  KeySpan,  will  become  president  and chief
operating officer of HoldCo. 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 HoldCo will be comprised of 15 members, six
from the  Company,  six from  KeySpan and three  additional  persons  previously
unaffiliated with either company.


                                       70

<PAGE>

In March 1997, the Company and the Brooklyn Union Gas Company  (Brooklyn  Union)
filed a joint  petition with the PSC seeking  approval,  under section 70 of the
New York Public  Service Law, of the KeySpan  Agreement by which the Company and
KeySpan each would become  subsidiaries  of HoldCo through an exchange of shares
of common stock with HoldCo. In addition,  the petition called for approximately
$1.0 billion of savings attributable to operating synergies that are expected to
be realized over the 10-year period following the combination to be allocated to
customers,  net of transaction costs for the combination.  On December 10, 1997,
Brooklyn  Union,  the  Company,  the  Staff of the PSC and three  other  parties
entered into a Settlement  Agreement  (Stipulation)  resolving  all issues among
them in the proceeding.  Hearings on the Stipulation  were held in early January
1998 and, on February 4, 1998, the PSC approved, effective February 5, 1998, the
Stipulation,  modified  only to reduce  Brooklyn  Union's  earnings  cap for the
remaining years of its rate plan.

Under the  Stipulation,  a three-year gas rate plan covering the period December
1, 1997  through  November  30, 2000 will be  implemented  by the Company  which
provides for, among other things, an estimated  reduction in customers' bills of
approximately 3.9%, including fuel savings,  through at least November 30, 2000.
This gas rate reduction  will occur in three phases as follows:  (i) a reduction
in base  rates of  approximately  $12.2  million  to  reflect  decreases  in the
Company's  gas cost of service  effective on February 5, 1998;  (ii) a base rate
reduction of approximately $6.2 million associated with non-fuel savings related
to the  KeySpan  Transaction  to become  effective  on the  closing  date of the
transaction;  and (iii) an expected reduction in the Gas Adjustment Clause (GAC)
to reflect  annual fuel savings  associated  with the  transaction  estimated at
approximately $4.0 million, the actual level of which will be reflected in rates
if and when  they  actually  materialize.  The  Company  will be  subject  to an
earnings  sharing  provision  pursuant to which it will be required to credit to
core/firm  customers  60% of any utility  earnings up to 100 basis  points above
11.10% and 50% of any utility earnings in excess of 12.10% of the allowed return
on common equity. Both a customer service and a safety and reliability incentive
performance program will be implemented effective December 1, 1997, with maximum
pre-tax return on equity penalties of 40 and 12 basis points,  respectively,  if
the Company fails to achieve certain performance standards in these areas.

The Stipulation, which obligates the Company to reduce electric customers' bills
by  approximately  2.5%  resulting from the savings in operating and fuel costs,
related to synergy  savings,  also defers the time within which the PSC must act
on the Company's  pending  electric rate plan until July 1, 1998.  However,  any
reduction in customers'  bills would not become effective until the PSC sets the
Company's electric rates.

For Brooklyn  Union,  effective on the date of the  consummation  of the KeySpan
Transaction,  Brooklyn Union's base rates to core/firm customers will be reduced
by $23.9 million  annually.  In addition,  effective in the fiscal year in which
the KeySpan  Transaction  is  consummated,  Brooklyn Union will be subject to an
earnings  sharing  provision  pursuant to which it will be required to credit to
core/firm  customers  60% of any utility  earnings up to 100 basis  points above
certain  threshold  equity  return  levels over the term of the rate plan (other
than any earnings  associated  with discrete  incentives) and 50% of any utility
earnings  in  excess  of 100 basis  points  above  such  threshold  levels.  The
threshold  levels,  as  modified by the  February 5, 1998 Order,  are 13.75% for
fiscal year 1998,  13.50% for fiscal years 1999,


                                       71

<PAGE>

2000,  and 2001;  and  13.25% for fiscal  year  2002.  A safety and  reliability
incentive  mechanism will be implemented  effective on the consummation  date of
the KeySpan Transaction, with a maximum 12 basis point pre-tax penalty return on
common equity if Brooklyn Union fails to achieve  certain safety and reliability
performance standards.  With the exception of the simplification of the customer
service performance standards,  the current Brooklyn Union rate plan approved by
the PSC in 1996 remains  unchanged.  Any gas cost savings  allocable to Brooklyn
Union  resulting  from the KeySpan  Transaction  will be  reflected  in rates to
utility customers through the GAC as those savings are realized.

The  Stipulation  adopts  certain  affiliate  transaction   restrictions,   cost
allocation  and  financial  integrity  conditions,  and a  competitive  code  of
conduct.  These restrictions and conditions eliminate or relax many restrictions
currently applicable to Brooklyn Union in such areas as affiliate  transactions,
use of the name and  reputation  of Brooklyn  Union by  unregulated  affiliates,
common   officers  of  HoldCo,   the  utility   subsidiaries   and   unregulated
subsidiaries, dividend payment restrictions, and the composition of the Board of
Directors of Brooklyn Union.

The  Stipulation  also enables the utilities to form one or more shared services
subsidiaries to perform  functions common to both utilities and their affiliates
such as accounting,  finance, human resources, legal and information systems and
technology to realize synergy savings.

Note 4.  Rate Matters

Electric

In April 1996,  the PSC issued an order  directing the Company to file financial
and other information  sufficient to provide a legal basis for setting new rates
for the three-year  period 1997 through 1999. In compliance with the order,  the
Company  submitted  a  multi-year  rate plan  (Plan) in  September  1996.  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 FCA, over a two-year period.
Pursuant to the provisions of the Stipulation discussed above, under the heading
KeySpan Energy Corporation Transaction, the PSC has until July 1, 1998 to render
a decision on this filing.

As an interim  measure,  pending the consummation of the LIPA Transaction or the
adjudication of its electric rate filing, the Company submitted petitions in May
1997 and December 1997 requesting PSC approval to extend, through the rate years
ending  November 30, 1996 and 1997,  respectively,  the  provisions  of its 1995
electric rate order (1995 Order).  These  petitions  were approved by the PSC in
December 1997 and April 1998, respectively.

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.


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<PAGE>

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 was subject to a
maximum  penalty of 38 basis points of the allowed  return on common  equity and
could earn up to 4 basis points under the customer service program.  Pursuant to
the Stipulation,  the Company's  customer service  incentive program was further
modified to eliminate the 4 basis point reward and increased the maximum penalty
which can be incurred under the these programs from 38 to 62 basis points.

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, 1997, the Company earned 12.7 basis points,
or  approximately  $2.9  million,  net  of  tax  effects,  as a  result  of  its
performance under all incentive programs.  For the rate years ended November 30,
1996 and 1995,  the  Company  earned 20 and 19 basis  points,  respectively,  or
approximately $4.3 million and $4.0 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,  1997,  the  amount to be  returned  to
customers   resulting   from   the   revenue   and   expense    reconciliations,
performance-based  incentive  programs and associated  carrying  charges totaled
$4.1 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 March 1998. For the rate year ended November 30, 1996, the Company
recorded a net deferred  LRPP credit of  approximately  $14.5  million


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<PAGE>

which was subsequently applied as a reduction to the RMC upon the PSC's approval
of the Company's reconciliation filing in December 1996. For the rate year ended
November 30, 1995, the Company  recorded a net deferred 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.

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, 1997, 1996 and 1995, the Company earned $4.8 million, $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 the event  that the LIPA  Transaction  is not  consummated,  the  Company  is
currently  unable  to  predict  the  outcome  of the  electric  rate  proceeding
currently  before the PSC and its  effect,  if any, on the  Company's  financial
position, cash flows or results of operations.

Gas

In May 1997, the Company submitted a petition  requesting PSC approval to extend
through the rate year ending November 30, 1997, the gas excess earnings  sharing
mechanism  established  in its prior  three-year gas rate  settlement  agreement
which expired on November 30, 1996. Pursuant to this request, earnings in excess
of a return  on  common  equity of 11.0%  are to be  allocated  equally  between
customers and shareowners with the customers' share of excess earnings  credited
to  the  regulatory   asset  created  as  a  result  of  costs  associated  with
manufactured  gas plant (MGP) site  investigation  and remediation  costs.  This
request was approved by the PSC in December 1997. As a result of this mechanism,
the customer's  allocation of excess  earnings  amounted to $6.3 million for the
rate year ended  November 30, 1997, and will be applied to offset costs incurred
to investigate and remediate MGP sites.  The prior gas rate settlement  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 and 1995, the firm gas customers'  portion of gas excess
earnings  totaled  approximately  $10 million and $1 million,  respectively.  In
1997,  the  Company was granted  permission  by the PSC to apply the  customers'
portion of the gas excess earnings and associated  carrying charges for the 1996
and  1995  rate  years  to  the  recovery  of  deferred  costs  associated  with
post-retirement   benefits   other  than   pensions   and  costs   incurred  for
investigation and remediation of MGP sites.


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). The owners of NMP2
and their  respective  percentage  ownership are as follows:  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  205 MW.  The
Company's   net  utility  plant   investment,   excluding   nuclear  fuel,   was
approximately $689 million at March 31, 1998, $710 million at March 31, 1997 and
$715 million at December 31, 1996. The accumulated  provision for  depreciation,
excluding decommissioning costs, was approximately $196 million and $175 million
at March 31, 1998 and 1997, respectively, and $169 million at December 31, 1996.
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.


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<PAGE>

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 the year ended March 31,
1998 and for the three months  ended March 31,  1997,  this totaled $1.4 million
and $0.4 million,  respectively. For the years ended December 31, 1996 and 1995,
this totaled $1.4 million and $1.2 million,  respectively.  As discussed in Note
2, the LIPA  Transaction  contemplates  that LIPA will acquire the Company's 18%
interest in NMP2.

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 $309 million in 2026 dollars ($155
million in 1998 dollars).  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
decommissioning  costs recorded as depreciation expense for the year ended March
31, 1998 and the three  months  ended March 31,  1997,  totaled $2.2 million and
$0.5  million,  respectively,  and $3.9  million and $2.3  million for the years
ended December 31, 1996 and 1995, respectively.  The accumulated decommissioning
costs  collected in rates  through March 31, 1998 and 1997 and December 31, 1996
amounted to $17.7 million, $15.5 million and $14.9 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 March
31, 1998, the balance in these funds,  including  reinvested  net earnings,  was
approximately $17.9 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 FASB  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.  Discussions of the issues expressed in
the  exposure  draft are  ongoing.  If the  Company  was  required to record the
present value of its share of NMP2 decommissioning costs on its Balance Sheet as
of March  31,  1998,  the  Company  would  have to  recognize  a  liability  and
corresponding  increase to nuclear  plant of  approximately  $62  million.  Upon
consummation of the LIPA Transaction,  LIPA will acquire the Company's  interest
in NMP2 as well as the trusts referred to above.

Nuclear Plant Insurance

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


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<PAGE>

The  Price-Anderson  Amendments  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 of up to $76 million for each nuclear 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 billion 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 $1.6 million per loss. This level of insurance is in excess of the
NRC 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 $0.7 million.

Note 6. Capital Stock

Common Stock

Currently  the Company has  150,000,000  shares of authorized  common stock,  of
which  121,727,040  were issued and 46,281 shares were held in Treasury at March
31,  1998.  The Company  has  1,644,865  shares  reserved  for sale  through its
Employee Stock Purchase Plan,  2,829,968 shares committed to the Investor Common
Stock Plan and 86,099 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 3, the Company has granted
KeySpan the option to purchase,  under certain circumstances,  23,981,964 shares
of common stock at a price of $19.725 per share. In connection with such option,
the Company has received  shareowner  approval to increase the authorized shares
of common stock to 160,000,000.

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 March  31,  1998 and 1997 and  December  31,  1996  amounted  to
approximately  $675,  $643 and $637  million,  respectively,  compared  to their
carrying  amounts of $639,  $640 and $640 million,  respectively.  For a further
discussion on the basis of the fair value of the securities discussed above, see
Note 1.


                                       76

<PAGE>

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

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
Series                          Redemption Provision       Number of Shares        Redemption Amounts
                             Beginning        Ending
-------------------------------------------------------------------------------------------------------------
<S>                           <C>             <C>              <C>                     <C>       
6.875% Series UU              10/15/99        10/15/19         112,000                 $2,800,000
=============================================================================================================

</TABLE>

The  aggregate  par value of  preferred  stock  required to be redeemed  through
sinking  funds during the fiscal year ended March 31, is $2.8 million in each of
the years 2000,  2001,  2002 and 2003.  The Company also 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 UU.

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>
------------------------------------------------------------------------------------------------------------
        Series               Redemption Date         Number of Shares              Redemption 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>

Preferred Stock Subject to Optional Redemption

The Company has the option to redeem certain series of its preferred  stock. For
the series  subject to optional  redemption  at March 31, 1998,  the call prices
were as follows:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
       Series                               Call Price                     Redemption Amounts
-----------------------------------------------------------------------------------------------------------
<S>                                           <C>                              <C>        
  5.00%  Series B                             $101.00                          $10,100,000
  4.25%  Series D                              102.00                            7,140,000
  4.35%  Series E                              102.00                           20,400,000
  4.35%  Series F                              102.00                            5,100,000
  5 1/8%  Series H                             102.00                           20,400,000
  5 3/4%  Series I - Convertible               100.00                            1,474,300
  7.40%  Series L                              102.07                           15,361,535
  $1.95  Series NN                              26.95                           41,880,300
===========================================================================================================
</TABLE>

On April 17,  1998,  the  Company  exercised  its option to redeem its  callable
preferred stock and called for redemption on May 19, 1998 all of the outstanding
shares of the  preferred  stock  series  noted above for a total of $122 million
including approximately $5 million of call premiums.

Preference Stock

At March 31, 1998, 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 1997, due not later than
June 30,  1998,  is  estimated  at $25  million.  It is  anticipated  that  this
requirement will be satisfied with retired G&R Bonds, property additions, or any
combination thereof.


                                       77

<PAGE>

Upon  consummation of the LIPA  Transaction,  all of the Company's series of G&R
Bonds will be assumed by LIPA.  LIPA has indicated that it intends to redeem all
such G&R Bonds as soon as practicable after the closing of the LIPA Transaction.

1989 Revolving Credit Agreement

The Company has available  through  October 1, 1998, $250 million under its 1989
Revolving Credit Agreement (1989 RCA). This line of credit is secured by a first
lien  upon the  Company's  accounts  receivable  and fuel  oil  inventories.  In
February 1997, the Company  utilized $30 million in interim  financing under the
1989 RCA,  which was repaid in March 1997,  and $40 million in July 1997,  which
was repaid in August 1997. At March 31, 1998, no amounts were outstanding  under
the 1989  RCA.  The  Company  has  filed,  with the  lending  institutions,  the
documentation  necessary to terminate the 1989 RCA effective upon the closing of
the LIPA and KeySpan Transactions.

Authority Financing Notes

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

Tender  requirements  of  Authority  Financing  Notes at March 31,  1998 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 2000
                   3.58%       1985 A,B      150,000      Tendered annually on March 1
EFRBs              3.70%        1993 A        50,000      Tendered weekly
                   3.70%        1993 B        50,000      Tendered weekly
                   3.70%        1994 A        50,000      Tendered weekly
                   3.70%        1995 A        50,000      Tendered weekly
                   3.55%        1997 A        24,880      Tendered weekly
==============================================================================================================
</TABLE>

The 1997,  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  $408  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                                    10/26/00
                                  1995 A                                     8/24/98
                                  1997 A                                    12/30/98
=================================================================================================================
</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.

In accordance with the LIPA Agreement, LIPA will assume substantially all of the
tax-exempt  authority  financing  notes.  HoldCo will issue a promissory note to
LIPA for a portion of the tax-exempt  debt borrowed to support  LILCO's  current
gas operations, with terms identical to those currently outstanding. The Company
currently  estimates the amount of this promissory note to be approximately $250
million.


                                       78

<PAGE>

Fair Values of Long-Term Debt

The carrying  amounts and fair values of the Company's  long-term  debt at March
31, 1998 and 1997 and December 31, 1996 were as follows:
<TABLE>
<CAPTION>
Fair Value                                                                              (In thousands of dollars)
-----------------------------------------------------------------------------------------------------------------
                                        March 31, 1998          March 31, 1997            December 31, 1996
-----------------------------------------------------------------------------------------------------------------
<S>                                       <C>                     <C>                         <C>       
General and Refunding Bonds               $1,288,470              $1,314,273                  $1,571,745
Debentures                                 2,407,178               2,256,573                   2,271,095
Authority Financing Notes                    987,646                 959,092                     950,758
=================================================================================================================
Total                                     $4,683,294              $4,529,938                  $4,793,598
=================================================================================================================
Carrying Amount                                                                      (In thousands of dollars)
-----------------------------------------------------------------------------------------------------------------
                                        March 31, 1998          March 31, 1997           December 31, 1996
-----------------------------------------------------------------------------------------------------------------
<S>                                       <C>                     <C>                         <C>       
General and Refunding Bonds               $1,286,000              $1,286,000                  $1,536,000
Debentures                                 2,270,000               2,270,000                   2,270,000
Authority Financing Notes                    940,555                 916,675                     916,675
=================================================================================================================
Total                                     $4,496,555              $4,472,675                  $4,722,675
=================================================================================================================
</TABLE>

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

Debt Maturity Schedule

The total long-term debt maturing in each of the next five years ending March 31
is as follows:  1999, $101 million;  2000, $490 million; 2001, $1 million; 2002,
$146 million; and 2003, $154 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  ss.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.

The Primary Plan's funded status and amounts  recognized on the Balance Sheet at
March 31, 1998 and March 31, 1997 and December 31, 1996 were as follows:
<TABLE>
<CAPTION>
                                                                                            (In thousands of dollars)
---------------------------------------------------------------------------------------------------------------------
                                                      March 31, 1998     March 31, 1997       December 31, 1996
---------------------------------------------------------------------------------------------------------------------
  Actuarial present value of benefit obligation
<S>                                                       <C>                  <C>                     <C>     
    Vested benefits                                        $661,075            $642,392                $547,002
    Nonvested benefits                                       59,268              57,960                  55,157
=====================================================================================================================
  Accumulated Benefit Obligation                           $720,343            $700,352                $602,159
=====================================================================================================================
  Plan assets at fair value                                $919,100            $744,400                $746,400
  Actuarial present value of projected benefit
   obligation                                               825,159             807,703                 689,661
---------------------------------------------------------------------------------------------------------------------
  Projected benefit obligation less (greater) than
   plan assets                                               93,941             (63,303)                 56,739
  Unrecognized net obligation                                62,652              69,399                  71,085
  Unrecognized net (gain)                                  (163,034)            ( 1,605)               (123,759)
=====================================================================================================================
  Net (Accrued) Prepaid Pension Cost                      $(  6,441)           $  4,491                $  4,065
====================================================================================================================
</TABLE>


                                       79

<PAGE>

The  increase  in the  present  value of the  accrued  benefit at March 31, 1997
compared to December  31, 1996,  is due  primarily to the change in the discount
rate from 7.25% to 7.00% and the use of updated actuarial assumptions,  relating
to mortality.

Periodic  pension  cost for the  Primary  Plan and the  significant  assumptions
consisted of the following:
<TABLE>
<CAPTION>
                                                                                                 (In thousands of dollars)
--------------------------------------------------------------------------------------------------------------------------
                                          Year Ended      Three Months Ended       Year Ended             Year Ended
                                        March 31, 1998      March 31, 1997     December 31, 1996       December 31, 1995
--------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                   <C>                 <C>                     <C>      
Service cost - benefits
 earned during the period                 $ 21,114              $ 4,645             $ 17,384                $  15,385
Interest cost on projected benefits
 obligation and  service cost               56,379               12,494               47,927                   45,987
Actual return on plan assets              (200,025)              (3,694)             (81,165)                (102,099)
Net amortization and deferral              151,438               (9,446)              33,541                   57,665
--------------------------------------------------------------------------------------------------------------------------
Net Periodic Pension Cost                 $ 28,906              $ 3,999             $ 17,687                $  16,938
==========================================================================================================================

--------------------------------------------------------------------------------------------------------------------------
                                        March 31, 1998      March 31, 1997      December 31, 1996      December 31, 1995
--------------------------------------------------------------------------------------------------------------------------
Discount rate for obligation                7.00%                7.00%                7.25%                  7.25%
Discount rate for expense                   7.00%                7.25%                7.25%                  7.25%
Rate of future compensation increases       4.50%                5.00%                5.00%                  5.00%
Long-term rate of return on  assets         8.50%                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 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 and pay a carrying charge on amounts in excess of the pension
rate allowance and the annual pension contributions contributed into the pension
fund.

In addition, effective December 1, 1997, in accordance with the Stipulation, the
Company  defers  the  difference   between  the  sum  of  gas  pension  and  gas
postretirement  benefit costs other than pension and the amounts provided for in
rates,  to the  extent  that such  differences  are in excess of or below  three
percent of the Company's pretax net income from its gas operations.  Such excess
will be transferred to a gas balancing account.  For a further discussion of the
Stipulation, see Note 3.

Supplemental Plan

The Supplemental Plan 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. The
provision for plan  benefits  totaled  approximately  $0.7 million for the three
months  ended  March 31, 1997 and $2.7  million  and $2.3  million for the years
ended  December  31, 1996 and 1995,  respectively.  For the year ended March 31,
1998, the Company  recorded a charge of  approximately  $31 million  relating to
certain  benefits  earned by its officers  relating to the  termination of their
annuity  benefits  earned  through the  supplemental  retirement  plan and other
executive retirement benefits. These charges, the cost of which are borne by the
Company's  shareowners,  result  from  provisions  of the  officers'  employment
contracts,  including  the  Chairman's  employment  contract,  and  the  pending
transactions  with LIPA and KeySpan  which affect the timing of when these costs
are recorded.


                                       80

<PAGE>

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 $132,000 for the year ended March 31,
1998,  $34,000  for the three  months  ended  March 31,  1997 and  $127,000  and
$114,000 for the years ended December 31, 1996 and 1995, respectively.

Postretirement Benefits Other Than Pensions

In addition to providing pension benefits,  the Company provides certain medical
and life  insurance  benefits  to 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 was phased into and
fully  reflected  in rates  beginning  December  1,  1996  with the  accumulated
regulatory  asset to be  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 addition, effective December 1, 1997, in accordance with the Stipulation, the
Company  defers  the  difference   between  the  sum  of  gas  pension  and  gas
postretirement  benefit costs other than pension and the amounts provided for in
rates,  to the  extent  that such  differences  are in excess of or below  three
percent of the Company's pretax net income from its gas operations.  Such excess
will be transferred to a gas balancing account.  For a further discussion of the
Stipulation, see Note 3.

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.  The Company funded the trusts
with approximately $21 million for the year ended March 31, 1998, $5 million for
the three  months  ended  March 31, 1997 and $18 million and $50 million for the
years ended December 31, 1996 and 1995,  respectively.  In May 1998, the Company
funded an  additional  $250  million into the trusts,  representing  obligations
related to the electric  business unit  employees.  The Company secured a bridge
loan to fund these trusts.


                                       81

<PAGE>

Accumulated  postretirement  benefit obligation other than pensions at March 31,
1998, March 31, 1997 and December 31, 1996 was as follows:
<TABLE>
<CAPTION>
                                                                                                 (In thousands of dollars)
--------------------------------------------------------------------------------------------------------------------------
                                                    March 31, 1998           March 31, 1997          December 31, 1996
--------------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>                     <C>                       <C>     
Retirees                                                $157,380                $169,655                  $156,181
Fully eligible plan participants                          60,711                  62,491                    56,950
Other active plan participants                           140,850                 183,526                   152,627
--------------------------------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation           $358,941                $415,672                  $365,758
Plan assets                                              108,165                  80,533                    74,692
--------------------------------------------------------------------------------------------------------------------------

Accumulated postretirement benefit
 obligation in excess of plan assets                     250,776                 335,139                   291,066
Unrecognized prior  service costs                          (175)                   (185)                     (188)
Unrecognized net gain                                    102,346                  28,563                    75,309
===========================================================================================================================
Accrued Postretirement Benefit Cost                     $352,947                $363,517                  $366,187
===========================================================================================================================
</TABLE>

The  increase  in the  present  value of the  accrued  benefit at March 31, 1997
compared to December  31,  1996 is due to the change in the  discount  rate from
7.25%  to  7.00%  and the  use of  updated  actuarial  assumptions  relating  to
mortality.

The change in the accumulated  postretirement  benefit obligation from March 31,
1997 to March 31,  1998  reflects a decrease in the  healthcare  cost trend rate
based on the  company's  review of the  medical  plan cost  experience  and also
revised assumptions with respect to future compensation increases, mortality and
the  percentage  of  employees  who are  assumed  to be  married  at the time of
retirement.

At March 31, 1998,  March 31, 1997 and December 31, 1996 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 and the  significant
assumptions consisted of the following:
<TABLE>
<CAPTION>
                                                                                                (In thousands of dollars)
--------------------------------------------------------------------------------------------------------------------------
                                        Year Ended        Three Months Ended       Year Ended             Year Ended
                                      March 31, 1998        March 31, 1997      December 31, 1996     December 31, 1995
--------------------------------------------------------------------------------------------------------------------------
<S>                                      <C>                   <C>                   <C>                  <C>      
Service cost - benefits
 earned during the period                $ 12,204              $ 2,821               $ 10,690             $   9,082
Interest cost on projected benefits
 obligation and  service cost              27,328                6,642                 25,030                22,412
Actual return on plan assets               (6,632)                (591)                (3,046)               (1,034)
Net amortization and deferral             (10,000)              (3,446)               (12,175)              (14,699)
--------------------------------------------------------------------------------------------------------------------------
Net Periodic Pension Cost                $ 22,900              $ 5,426               $ 20,499             $  15,761
==========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>

--------------------------------------------------------------------------------------------------------------------------
                                             March 31, 1998     March 31, 1997   December 31, 1996     December 31, 1995
--------------------------------------------------------------------------------------------------------------------------
<S>                                               <C>               <C>                <C>                  <C>  
Discount rate for obligation                      7.00%             7.00%              7.25%                7.25%
Discount rate for expense                         7.00%             7.25%              7.25%                7.25%
Rate of future compensation increases             4.50%             5.00%              5.00%                5.00%
Long-term rate of return on assets                8.50%             7.50%              7.50%                7.50%
==========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>

The actuarial assumptions used for postretirement benefit plans are:

--------------------------------------------------------------------------------------------------------------------------
(In thousands of dollars)                                        March 31, 1998     March 31, 1997    December 31, 1996
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>               <C>                 <C>     
Health care cost trend                                               5.00%(a)          8.00%(b)            8.00%(b)
Effect of one percent increase in health care cost trend rate:
On cost components                                                       $  7            $ 1               $ 5
On accumulated benefit obligation                                         $42            $59               $43
==========================================================================================================================
</TABLE>
(a) Per year indefinitely
(b) Gradually declining to 6.0% in 2001 and thereafter.


                                       82

<PAGE>

Note 9. Federal Income Tax
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)
--------------------------------------------------------------------------------------------------------------------------
                                                     3/31/98                      3/31/97                 12/31/96
--------------------------------------------------------------------------------------------------------------------------
Deferred Tax Assets
<S>                                                <C>                           <C>                    <C>        
Net operating loss carryforwards                   $         -                   $   93,349             $   145,205
Reserves not currently deductible                       39,667                       56,749                  58,981
Tax depreciable basis in excess of                      10,559                       33,848                  34,314
 book
Nondiscretionary excess credits                         24,858                       27,037                  27,700
Credit carryforwards                                    40,318                      128,469                 135,902
Other                                                  261,729                      225,885                 186,907
--------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Assets                          $   377,131                   $  565,337              $  589,009
--------------------------------------------------------------------------------------------------------------------------
Deferred Tax Liabilities
1989 Settlement                                     $2,169,909                   $2,165,462              $2,163,239
Accelerated depreciation                               650,562                      642,656                 642,702
Call premiums                                           38,698                       43,617                  44,846
Rate case deferrals                                        564                        2,579                   2,127
Other                                                   56,762                       38,117                  33,496
--------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Liabilities                       2,916,495                    2,892,431               2,886,410
==========================================================================================================================
Net Deferred Tax Liability                          $2,539,364                   $2,327,094              $2,297,401
==========================================================================================================================

SFAS No. 109 requires  utilities to establish  regulatory assets and liabilities
for the portion of its  deferred  tax assets and  liabilities  that have not yet
been  recognized  for  ratemaking  purposes.   The  major  components  of  these
regulatory assets and liabilities are as follows:
                                                                                                (In thousands of dollars)
--------------------------------------------------------------------------------------------------------------------------
                                                     3/31/98                      3/31/97                 12/31/96
--------------------------------------------------------------------------------------------------------------------------
Regulatory Assets
1989 Settlement                                     $1,652,412                   $1,659,065              $1,660,871
Plant items                                            100,661                      120,460                 125,976
Other                                                  (15,141)                     (12,361)                (14,069)
==========================================================================================================================
Total Regulatory Assets                             $1,737,932                   $1,767,164              $1,772,778
==========================================================================================================================

Regulatory Liabilities

Carryforward credits                                $   38,720                   $   64,548              $   68,421
Other                                                   40,193                       35,829                  34,466
========================================= =============================== ========================= ======================
Total Regulatory Liabilities                        $   78,913                   $  100,377              $  102,887
========================================= =============================== ========================= ======================
</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)
-------------------------------------------------------------------------------------------------------------------------
                                             Year Ended      Three Months Ended     Year Ended           Year Ended
                                           March 31, 1998      March 31, 1997    December 31, 1996    December 31, 1995
-------------------------------------------------------------------------------------------------------------------------
<S>                                            <C>               <C>                  <C>                   <C>     
Income before federal income tax               $594,893          $143,910             $525,721              $508,824
Statutory federal income tax rate                   35%               35%                  35%                   35%
-------------------------------------------------------------------------------------------------------------------------
Statutory federal income tax                   $208,213          $ 50,369             $184,002              $178,088
Additions (reductions) in federal income
 tax
Excess of book over tax depreciation             17,912             4,356               18,339                18,588
1989 Settlement                                   4,212             1,053                4,212                 4,213
Interest capitalized                              2,962               588                2,270                 2,218
Tax credits                                      (2,464)             (940)              (4,383)               (1,025)
Tax rate change amortization                      2,223               815                3,686                 3,752
Allowance for funds used during                  (2,953)             (583)              (2,305)               (2,392)
 construction
Other items                                       2,549               555                3,436                 2,096
-------------------------------------------------------------------------------------------------------------------------
Total Federal Income Tax Expense               $232,654           $56,213             $209,257              $205,538
=========================================================================================================================
Effective Federal Income Tax Rate                 39.1%             39.1%                39.8%                 40.4%
=========================================================================================================================
</TABLE>


                                       83

<PAGE>

The Company currently has tax credit carryforwards of approximately $40 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
$31 million and research  and  development  credits  totaling  approximately  $9
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. A settlement resolving all audit issues
was reached  between the Company and the Internal  Revenue  Service in May 1998.
The settlement  provided for the payment of taxes and interest of  approximately
$9 million and $35  million,  respectively,  which the Company made in May 1998.
The Company had previously  provided  reserves  adequate to cover such taxes and
interest.

Note 10. 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 LIPA,  an  agency  of the  State of New  York,  for its  subsequent
decommissioning. In February 1992, the Company transferred ownership of Shoreham
to LIPA. In May 1995,  the NRC  terminated  LIPA's  possession-only  license for
Shoreham which  signified the NRC's approval that  decommissioning  was complete
and that the site is suitable for unrestricted use.

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. For a further discussion of
the FRA, see Note 1.

Pursuant to the 1989 Settlement,  the Company was required to reimburse LIPA for
all of its costs associated with the  decommissioning  of Shoreham.  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. At March 31,
1998,  Shoreham   post-settlement  costs  totaled  approximately  $1.2  billion,
consisting of $587 million of property taxes and payments-in-lieu-of-taxes,  and
$568 million of  decommissioning  costs, fuel disposal costs and all other costs
incurred at Shoreham after June 30, 1989.

Note 11. The Class Settlement

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

The  Class  Settlement  provides  the  Company's  electric  customers  with rate
reductions  aggregating  $390 million 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 March  31,  1998  reflects  the  present  value of the  remaining
reductions  to be refunded to customers.  The remaining  reductions to customers
bills, amounting to approximately $130 million as of March 31, 1998, consists of
approximately  $10 million for the two-month period beginning April 1, 1998, and
$60 million for each of the 12-month periods beginning June 1, 1998 and 1999.


                                       84

<PAGE>

Note 12. Commitments and Contingencies

Electric

The Company has entered into contracts with numerous Independent Power Producers
(IPPs) and the New York Power Authority (NYPA) for electric generating capacity.
Under the terms of the agreement with NYPA,  which is set to expire in May 2014,
the Company may purchase up to 100% of the electric  energy produced at the NYPA
facility located within the Company's service  territory at Holtsville,  NY. The
Company is required to reimburse NYPA for the minimum debt service payments, and
to make fixed  non-energy  payments and expenses  associated  with operating and
maintaining the plant.

With respect to contracts  entered into with the IPPs,  the Company is obligated
to  purchase  all the energy they make  available  to the Company at prices that
often exceed current market  prices.  However,  the Company has no obligation to
the IPPs if they fail to deliver  energy.  For purposes of the table below,  the
Company has assumed full  performance  by the IPPs,  as no event has occurred to
suggest anything less than full performance by these parties.

The  Company  also has  contracted  with NYPA for firm  transmission  (wheeling)
capacity in connection with a transmission cable which was constructed, in part,
for the  benefit of the  Company.  In  accordance  with the  provisions  of this
agreement,  which expires in 2020, the Company is required to reimburse NYPA for
debt service payments and the cost of operating and maintaining the cables.  The
cost of such  contracts is included in electric fuel expense and is  recoverable
through rates.

The following table represents the Company's  commitments  under purchased power
contracts.
<TABLE>
<CAPTION>
Electric Operations                                                                              (In millions of dollars)
-------------------------------------------------------------------------------------------------------------------------
                                         NYPA Holtsville
                            -------------------------------------------
                                           Other Fixed                      Firm                              Total
For the fiscal years ended  Debt Service     Charges        Energy*     Transmission        IPPs*           Business*
-------------------------------------------------------------------------------------------------------------------------
<S>                             <C>           <C>              <C>           <C>               <C>              <C>     
1999                           $ 21.7      $  14.7          $  6.7        $ 25.7            $  127.6         $  196.4
2000                             21.7         13.7             6.7          26.0               132.7            200.8
2001                             21.8         14.6             7.2          27.8               135.8            207.2
2002                             21.9         16.3             8.7          27.8               139.5            214.2
2003                             22.0         16.7             9.0          27.9               137.9            213.5
Subsequent Years                232.4        217.1           119.8         474.0               957.5          2,000.8
-------------------------------------------------------------------------------------------------------------------------
Total                          $341.5       $293.1          $158.1        $609.2            $1,631.0         $3,032.9
-------------------------------------------------------------------------------------------------------------------------
Less: Imputed Interest         $166.8       $154.1          $ 85.3        $381.9            $  805.2         $1,593.3
-------------------------------------------------------------------------------------------------------------------------
Present Value of Payments      $174.7       $139.0          $ 72.8        $227.3            $  825.8         $1,439.6
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

*Assumes full performance by the IPPs and NYPA.

Gas
In order  to  provide  for  sufficient  supplies  of gas for the  Company's  gas
customers,  the Company  has entered  into  long-term  firm gas  transportation,
storage and supply  contracts which contain  provisions that require the Company
to make fixed  payments  (demand  charges)  even if the  services  are not fully
utilized.  The cost of such  contracts  is included  in gas fuel  expense and is
recoverable  through rates.  The table below sets forth the Company's  aggregate
obligation under these commitments which extend through 2014.

      Gas Operations                              (In millions of dollars)
      ---------------------------------------------------------------------
      For the fiscal years ended
      1999                                                       $111.73
      2000                                                        110.37
      2001                                                        101.33
      2002                                                         97.81
      2003                                                         91.69
      Subsequent Years                                            371.20
      ---------------------------------------------------------------------
      Total                                                      $884.13
      Less: Imputed Interest                                      258.45
      =====================================================================
      Present Value of Payments                                  $625.68
      =====================================================================


                                       85

<PAGE>

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 1997 and 1998, 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 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
called for a competitive  wholesale power market to be in place by early 1997 to
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 (except the Company
and Niagara Mohawk Power  Corporation) 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.  The PSC has now approved settlement agreements with each of the five
New  York  utilities  that  were  required  to file  restructuring  plans in the
Competitive  Opportunities  Proceeding.  LILCO and  Niagara  Mohawk  were exempt
however, on February 18,1998 the PSC also approved a settlement agreement on the
Niagara Mohawk PowerChoice restructuring proposal that had been filed in October
1995.

In general,  the terms of the agreements  vary from three to five years with all
agreements  calling  for some  rate  reductions,  structural  separation  of the
generation and power delivery function,  divestiture of fossil generation,  full
retail  access in two to four years,  and the  imposition  of a system  benefits
charge to cover the  costs of  research  and  development  (R&D),  conservation,
low-income  and  environmental  programs.  In each  case,  the PSC is giving the
utility a  reasonable  opportunity  to recover all  prudently-incurred  stranded
costs.

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


                                       86

<PAGE>

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.  On  December  31,  1996,  the New York Power  Pool  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.  Subsequent to the FERC filing in January 1997, the New York
State  utilities made three  relating  filings with the FERC: (i) a supplemental
filing,  providing additional details regarding the creation of a New York State
Reliability  Council,  in  May  1997;  (ii)  a  request  for  market-based  rate
authority,  by six of the New  York  utilities,  in  August  1997;  and  (iii) a
supplemental  filing with the FERC on December  19, 1997 which  expands upon and
provides additional details with respect to the January 1997 filing.

The PSC has taken the position 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 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, the  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.  At the
request of the


                                       87

<PAGE>

Energy  Association and Public Utility Law Project of New York (PULP), the Court
has  extended  the time in which the Energy  Association  and PULP must  perfect
their appeals until July 6, 1998.

The Electric Industry - Federal Regulatory Issues

In April 1996, in response to its Notice of Proposed  Rulemaking issued in March
1995,  the  FERC  issued  Orders  888 and 889  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.

Order 888 required  utilities to file open access tariffs under which they would
provide  transmission  services,  comparable  to those  which  they  provide  to
themselves  and to third parties on a  non-discriminatory  basis.  Additionally,
utilities  must use these same  tariffs  for their own  wholesale  sales.  Order
888-A, issued in March 1997, generally reaffirmed the FERC's basic determination
in Order 888. One pertinent change made in 888-A, however, was that the FERC, as
opposed to the states, will be the primary forum for determining  stranded costs
in cases  involving  municipal  annexation.  Order 888-B,  issued November 1997,
reaffirmed 888-A's findings.

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.

On May 14, 1997,  the FERC approved the  settlement  agreement  that the Company
filed (with five other  entities)  concerning  the rates for the Company's  open
access electric tariff. The effective date for those rates was July 9, 1996. The
Company and four other New York utilities are seeking review of certain non-rate
aspects of the FERC's open access  transmission  tariff orders in the U.S. Court
of Appeals for the D.C. Circuit.

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.

Order  889-A  and  889-B,  issued  in March  and  November  1997,  respectively,
generally   reaffirmed  and  clarified  the  original  Order  889.  Order  889-A
implemented new discounting  policies and required that all negotiations between
a transmission  provider and a potential customer take place on the transmission
pricing bulletin board and be visible to all.


                                       88

<PAGE>

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
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,  non-utility  generators
(NUGs).

The Public Utility Regulatory  Policies Act of 1978 (PURPA),  the goals of which
are 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.  The 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
the PURPA to purchase the output of certain of these generators, which are known
as qualified facilities (QFs).

For the years  ended March 31,  1998 and 1997,  the  Company  lost sales to NUGs
totaling  447 and 422  gigawatt  hours  (GWh)  representing  a loss in  electric
revenues  net of fuel  (net  revenues)  of  approximately  $36  million  and $34
million,   respectively  or  2.0%  and  1.9%  of  the  Company's  net  revenues,
respectively.

For the year ended  December 31, 1996,  the Company lost sales to NUGs  totaling
422 GWh  representing  a loss in  electric  net  revenues of  approximately  $34
million, or 1.9% of the Company's net revenues.  For the year ended December 31,
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 1999 sales losses to NUGs will be 447
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 for the  years  ended  March  31,  1998 and 1997,
approximated 220 megawatts (MW) and 226 MW, respectively.  The Company estimates
that  purchases  from QFs required by federal and state law cost the Company $71
million and $64 million in 1998 and 1997, respectively,  more than it would have
cost had the Company purchased the power in the open market or generated it.

For the years ended December 31, 1996 and 1995, QFs offered approximately 218 MW
and 205 MW, respectively. The Company estimates that purchases from QFs required
by federal  and state law cost the  Company  $63 million and $53 million for the
years ended  December 31, 1996 and 1995,  respectively,  more than it would have
cost had the Company purchased the power in the open market or generated it.


                                       89

<PAGE>

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 New York Power  Authority  (NYPA)  power for
economic  development.  The Company estimates that for the years ended March 31,
1998 and 1997, NYPA power displaced  approximately 373 GWh and 424 GWh of annual
energy sales,  respectively.  Net revenue loss  associated with these volumes of
sales is approximately $23 million,  or 1.2% of the Company's 1998 net revenues,
and $27 million,  or 1.5% of the  Company's  1997 net revenues.  Currently,  the
potential  loss of  additional  load is limited by  conditions  in the Company's
transmission agreements with NYPA.

The Company  estimates that for the years ended December 31, 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.

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.


                                       90

<PAGE>

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  its decision  once that
decision  becomes final,  which is not expected for several months.  The Company
and Suffolk County  submitted briefs in July 1997 addressing the pricing for the
200 MW of power.  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.

The Company has entered into  discussions with the DEC which is expected to 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  preliminary
investigations  conducted at each of these six sites, current estimates indicate
that it may cost  approximately  $54 to $92 million to investigate and remediate
all of these sites. In considering the range of possible remediation  estimates,
the Company felt it appropriate to record a $54 million liability


                                       91

<PAGE>

reflecting  the present value of the future stream of payments  amounting to $70
million to investigate and remediate  these sites.  The Company used a risk-free
rate of 6.0% to discount this obligation. The Company believes that the PSC will
provide  for future  recovery  of these  costs and has  recorded  a $54  million
regulatory  asset. The Company's rate settlement which the PSC approved February
4, 1998 as discussed in Note 3 of Notes to Financial Statements,  allows for the
recovery of MGP expenditures from gas customers.

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. In
January  1998,  the  Company  commenced  a similar  action  against the same and
certain  additional  insurer  defendants in New York State Supreme Court,  First
Department;  the federal court action was subsequently  dismissed in March 1998.
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.

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,
completed performance of a Remedial Investigation and Feasibility Study (RI/FS),
which was conducted  under an ACO with the EPA. In December 1997, the EPA issued
its Record of Decision  (ROD),  setting forth the final remedial action selected
for this  site.  In the ROD,  the EPA  estimated  that the  present  cost of the
selected remedy for the site is $17.3 million.  At this time, the Company cannot
predict with reasonable  certainty the actual cost of the selected  remedy,  who
will  implement  the remedy,  or the cost,  if any, to the Company.  Under a PRP
participation  agreement, the Company previously was responsible for 8.2% of the
costs associated with the RI/FS. The Company's  allocable share of liability for
the remediation activities has not yet been determined. The Company has recorded
a liability of approximately $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.  Certain of the PRPs,  including the Company and several  other  utilities
formed  a  PRP  group,  signed  an  ACO,  and  have  developed  a  workplan  for
investigating  environmental  conditions at the sites.  Documentation connecting
the Company to the sites  indicates  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.

In  addition,  the Company  was  notified  that it is a PRP at 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  transformers.  The Company is currently unable to determine
its share of costs of remediation at this site.


                                       92

<PAGE>

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.

The Owners  have also  entered  into an ACO with the DEC as a result of leaks of
dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to
participate  in and  separately  approve the reports and studies being  prepared
pursuant  to the ACO issued by the DEP.  In  addition,  the ACO  settles any DEC
claim for natural  resource  damages in connection with  historical  releases of
dielectric fluid from the Sound Cable.

In October 1995, 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 December 1996, a barge,  owned and operated by a third party,  dropped anchor
which then dragged over and damaged the Sound Cable, resulting in the release of
dielectric fluid into Long Island Sound.  Temporary clamps and leak abaters were
installed on the cables to stop the leaks.  Permanent  repairs were completed in
June 1997. The cost to repair the Sound Cable was  approximately  $17.8 million,
for which there was $15 million of insurance coverage.  The Owners filed a claim
and answer in response to the maritime limitation  proceeding  instituted by the
barge owner in the United States District Court,  Eastern  District of New York.
The claim seeks recovery of the amounts paid by insurance  carriers and recovery
of the costs  incurred for which there was no insurance  coverage.  Any costs to
repair the Sound Cable which are not  reimbursed  by a third party or 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.


                                       93

<PAGE>

Note 13. Business Segments

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)
--------------------------------------------------------------------------------------------------------------------------
                                        Year Ended        Three Months Ended        Year Ended            Year Ended
                                      March 31, 1998        March 31, 1997      December 31, 1996      December 31, 1995
--------------------------------------------------------------------------------------------------------------------------
Operating revenues
<S>                                       <C>                    <C>                <C>                     <C>    
Electric                                  $ 2,478                $  558             $ 2,467                 $ 2,484
Gas                                           646                   293                 684                     591
==========================================================================================================================
Total                                     $ 3,124                $  851             $ 3,151                 $ 3,075
==========================================================================================================================
Operating expenses
 (excludes federal income tax)
Electric                                  $ 1,595                $  400             $ 1,644                 $ 1,657
Gas                                           523                   204                 560                     478
==========================================================================================================================
Total                                     $ 2,118                $  604             $ 2,204                 $ 2,135
==========================================================================================================================
Operating income
 (before federal income tax)
Electric                                  $   883                $  158             $   823                 $   827
Gas                                           123                    89                 124                     113
==========================================================================================================================
Total operating income                    $ 1,006                $  247             $   947                 $   940
==========================================================================================================================
AFC                                       $    (8)               $   (2)            $   (6)                 $    (7)
Other income and deductions                    10                    (2)               (23)                     (38)
Interest charges                              409                   107                 451                     476
Federal income tax                            233                    56                 209                     206
==========================================================================================================================
Net Income                                 $  362                $   88             $   316                 $   303
==========================================================================================================================
Depreciation and Amortization
Electric                                   $  131                $   32             $   129                 $   122
Gas                                            28                     7                  25                      23
==========================================================================================================================
Total                                      $  159                $   39             $   154                 $   145
==========================================================================================================================
Construction and nuclear fuel
 expenditures*
Electric                                   $  181                $   35             $   165                 $   162
Gas                                            80                    16                  78                      84
==========================================================================================================================
Total                                      $  261                $   51             $   243                 $   246
==========================================================================================================================
</TABLE>
* Includes  non-cash  allowance  for other  funds used during  construction  and
excludes Shoreham post-settlement costs.
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
                                          March 31, 1998     March 31, 1997     December 31, 1996     December 31, 1995
--------------------------------------------------------------------------------------------------------------------------
Identifiable Assets
<S>                                            <C>              <C>                  <C>                  <C>    
Electric                                       $ 9,553          $10,048                $9,835              $10,020
Gas                                              1,219            1,134                 1,232                1,181
--------------------------------------------------------------------------------------------------------------------------
Total Identifiable Assets                       10,772           11,182                11,067               11,201
Assets Utilized for Overall
 Company Operations                              1,129              668                 1,143                1,326
==========================================================================================================================
Total Assets                                   $11,901          $11,850               $12,210              $12,527
==========================================================================================================================
</TABLE>


                                       94

<PAGE>

Note 14.  Disaggregated Condensed Balance Sheet (Unaudited)

Set forth below is the Company's condensed balance sheet at March 31, 1998 which
has been  disaggregated  pursuant  to the  terms of the LIPA  Agreement  to give
effect to the proposed LIPA transaction as if it had occurred on March 31, 1998.
The assets,  capitalization  and liabilities  attributable to HoldCo  Subsidiary
represent  the  Company's  transfer of its gas and  generation  business to such
subsidiary.  The assets,  capitalization  and  liabilities  attributable to LIPA
represent  those  items that will be  aqcquired  or assumed by LIPA  through its
acquisition of the Company's common stock. All such amounts exclude the proceeds
from the sale of common stock to LIPA. The disaggregated condensed balance sheet
was prepared by management of the Company,  and is subject to adjustment.  For a
further discussion of the LIPA Transaction, see Note 2.

<TABLE>
<CAPTION>
                                                                                                (In millions of dollars)
-------------------------------------------------------------------------------------------------------------------------
ASSETS                                                         LILCO          HoldCo Subsidiary             LIPA
<S>                                                        <C>                     <C>                     <C>     
-------------------------------------------------------------------------------------------------------------------------

Total Net Utility Plant                                     $3,814.1               $1,777.8                $2,036.3
-------------------------------------------------------------------------------------------------------------------------
Regulatory Assets

    Shoreham related                                         4,661.1                                        4,661.1
    Regulatory tax asset                                     1,737.9                   21.0                 1,716.9
    Other                                                      692.8                  430.1                   262.7
-------------------------------------------------------------------------------------------------------------------------
Total Regulatory Assets                                      7,091.8                  451.1                 6,640.7
------------------------------------------------------------------------------------------------------------------------
Nonutility Property and Other Investments                       50.8                   32.9                    17.9
Total Current Assets                                           858.3                  494.2                   364.1
Deferred Charges                                                85.7                   38.0                    47.7
-------------------------------------------------------------------------------------------------------------------------
Total Assets                                               $11,900.7               $2,794.0                $9,106.7
=========================================================================================================================
-------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
-------------------------------------------------------------------------------------------------------------------------
  Long term debt, including current maturities              $4,482.9               $1,130.5                $3,352.4
  Preferred stock, including current maturities                702.0                  363.0                   339.0
  Common Shareowner's Equity                                 2,662.5                  161.7                 2,500.8
-------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                        $7,847.4               $1,655.2                $6,192.2
Regulatory Liabilities                                         389.4                    1.6                   365.2
Current Liabilities                                            587.4                  433.0                   154.4
Deferred Credits                                             2,608.8                  211.2                 2,397.6
Operating Reserves                                             467.7                  470.4                    (2.7)
Commitments and Contingencies                                      -                      -                       -
-------------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities                       $11,900.7               $2,794.0                $9,106.7
=========================================================================================================================
</TABLE>

                                       95

<PAGE>

Note 15. Quarterly Financial Information (Unaudited)
Summarized quarterly financial data for 1998, 1997 and 1996 is as follows:

<TABLE>
<CAPTION>
                                                                (In thousands of dollars except earnings per common share)
----------------------------------------------------------------------------------------------------------------------------
                                                                         Fiscal Year Ended March 31, 1998
                                               -----------------------------------------------------------------------------
3 Months Ended                                 3/31/97          6/30/97         9/30/97         12/31/97          3/31/98
----------------------------------------------------------------------------------------------------------------------------
<S>                                           <C>              <C>             <C>              <C>              <C>     
Operating Revenues                            $851,182         $664,488        $852,408         $779,622         $827,576
Operating Income                               190,001          144,079         242,611          171,969          209,637
Net Income                                      87,697           45,161         144,384           56,756          115,939
Earnings for common stock                       74,728           32,193         131,435           43,807          102,992
Basic and diluted earnings per common share        .62              .26            1.09              .36              .85
----------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------
                                                                       Calendar Year Ended December 31, 1996
                                                          ------------------------------------------------------------------
3 Months Ended                                                3/31/96         6/30/96          9/30/96         12/31/96
----------------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>           <C>              <C>              <C>     
Operating Revenues                                             $864,214      $694,602         $849,775         $742,104
Operating Income                                                190,421       141,065          235,402          169,693
Net Income                                                       81,753        40,524          130,023           64,164
Earnings for common stock                                        68,682        27,453          116,972           51,141
Basic and diluted earnings per common share                         .57           .23              .97              .43
----------------------------------------------------------------------------------------------------------------------------
</TABLE>
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 March 31, 1998 and 1997, and
December 31, 1996 and the related  statements of income,  retained  earnings and
cash flows for the year ended March 31, 1998, the transition period from January
1, 1997 to March 31, 1997 and each of the two 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
March  31,  1998 and  1997,  and  December  31,  1996,  and the  results  of its
operations  and its cash flows for the year ended March 31, 1998, the transition
period  from  January 1, 1997 to March 31, 1997 and each of the two years in the
period ended December 31, 1996, in conformity with generally accepted accounting
principles.  Also, in our opinion, the related finacial statement schedule,  whe
considered  in  relation  to the basic  financial  statements  taken as a whole,
presents fairly in all material respects the information set forth therein.

As dicussed in Note 1 to the financial  statements,  during the year ended March
31, 1998 the Company changed its method of accounting for revenues  provided for
under the Rate Moderation Component.

Melville, New York
May 22, 1998


                                       96

<PAGE>

Item  9.  Changes  In And  Disagreements  With  Accountants  On  Accounting  And
          Financial Disclosures

Not applicable.


                                       97
<PAGE>

                                    PART III

Item 10.          Directors and Executive Officers of the Company

Directors of the Company

All Directors are elected annually.  Current information regarding the Company's
Directors follows:

William J.  Catacosinos:  Chairman of the Board of Directors and Chief Executive
Officer ("CEO") of LILCO since January 1984 and a Director since 1978; President
of LILCO from March 1984 to January  1987 and from March 1994 to December  1996.
Dr. Catacosinos,  68, is a resident of Mill Neck, Long Island. Received bachelor
of science  degree,  masters  degree in business  administration  and a doctoral
degree in economics from New York University. Member, boards of Atlantic Bank of
New York; Long Island Association;  Empire State Business Alliance; and a member
of the Advisory Committee of the Huntington Township Chamber Foundation.  Former
chairman and chief  executive  officer of Applied  Digital Data  Systems,  Inc.,
Hauppauge,  New York; chairman of the board and treasurer of Corometric Systems,
Inc. of Wallingford,  Connecticut; and assistant director at Brookhaven National
Laboratory, Upton, New York.

John H.  Talmage:  Director  of LILCO  since  1982.  Graduate  of the College of
Agriculture and Life Sciences,  Cornell University, Mr. Talmage is 68. President
since 1992 and director since 1960, Friar's Head Farm, Inc.; Chairman,  board of
directors, H.P. Hood, Inc. of Boston,  Massachusetts,  1980 to 1995; partner, HR
Talmage & Son Farm 1954 to present; director, Agway, Inc., 1967 to 1995; Curtice
Burns Foods,  Inc.,  1969 to 1984; and Suffolk  County Federal  Savings and Loan
Association, 1975 to 1982.

Basil A. Paterson:  Director of LILCO since 1983.  Received juris doctorate from
St. John's  University  School of Law.  Served as Secretary of State of New York
from 1979 to 1982, as Deputy Mayor of New York City, as a New York State Senator
and as a  commissioner  of the Port  Authority  of New York and New Jersey.  Mr.
Paterson,  72, is a partner in the law firm of Meyer, Suozzi, English and Klein,
P.C., Mineola, New York. Served as a professor at a number of universities, as a
member of the board of  editors of the New York Law  Journal  and as a member of
the State of New York Commission on Judicial Nomination.

George  Bugliarello:  Director of LILCO since 1990.  Received  doctor of science
degree in  engineering  from  Massachusetts  Institute of Technology and several
honorary  degrees  from  other  institutions.  Dr.  Bugliarello,  71,  served as
President of Polytechnic  University from 1973 to July 1994, and presently holds
the position of Chancellor.  Member, board of directors of the Lord Corporation,
Symbol Technologies,  Comtech  Telecommunications  Corp., the Teagle Foundation,
the Jura Corp., the Greenwall Foundation and Spectrum Information  Technologies,
Inc., and the ANSER Corporation.  Member of the Council on Foreign Relations and
National  Academy  of  Engineering.   Fellow,  the  American  Society  of  Civil
Engineers,  the American  Association for the Advancement of Science and the New
York Academy of Medicine; Founding Fellow, the American Institute of Medical and
Biological Engineering.  Previously held a NATO Senior Faculty Fellowship at the
Technical University of Berlin and the chairmanship on the


                                       98

<PAGE>

Committee on Science,  Engineering and Public Policy of the American Association
for  the  Advancement  of  Science  and  of  the  Board  on  Infrastructure  and
Constructed  Environment,  National  Research  Council.  Former  member  of  the
Scientific Committee of the Summer School on Environmental Dynamics in Venice.

George J. Sideris:  Director of LILCO since 1991.  Received  bachelors degree in
economics from New York  University.  Mr.  Sideris,  71, joined LILCO in 1984 as
Vice  President  of Finance  and Chief  Financial  Officer.  Became  Senior Vice
President  of Finance in 1987 and  retired in  January  1992.  Member,  board of
directors  of  Utilities  Mutual   Insurance   Company  through  December  1994.
Self-employed as a management and financial  consultant,  1981-1984.  Previously
served as a vice president of Qualpeco  Services,  Inc., and as a vice president
and chairman of the Northeast Operations Group of U.S. Industries, Inc.

A. James Barnes:  Director of LILCO since 1992.  Received  undergraduate  degree
from Michigan State University and juris doctorate from Harvard Law School.  Mr.
Barnes, 56, served as General Counsel of the U.S. Department of Agriculture from
1981 to 1983, as General  Counsel of the U.S.  Environmental  Protection  Agency
from 1983 to 1984 and as Deputy  Administrator  of the Agency from 1985 to 1988.
Previously  was a partner in the law firm of  Beveridge,  Fairbanks and Diamond,
Washington, D.C. and also served with the U.S. Department of Justice. Joined the
Indiana  University  School of Public and  Environmental  Affairs as its Dean in
1988.  Currently  serving as a member of the Board of Trustees  of the  National
Institute for Global Environmental Change.

Richard L. Schmalensee:  Director of LILCO since 1992.  Received doctoral degree
in economics and bachelor of science  degree in economics,  politics and science
from the  Massachusetts  Institute  of  Technology  ("MIT").  Gordon Y.  Billard
Professor of Economics and  Management at MIT's Sloan School since 1988.  Served
as member of the  President's  Council of Economic  Advisors  from 1989 to 1991.
Currently, Deputy Dean of the MIT Sloan School of Management and Director of the
MIT Center for Energy and Environmental Policy Research. Dr. Schmalensee, 54, is
a consultant to a variety of  government  agencies and private firms through the
National  Economic  Research  Associates  Inc.  on a range of  issues  including
aspects of utility regulation.

Renso L.  Caporali:  Director of LILCO since 1992.  Received  doctorate  and two
masters  degrees in  Aeronautical  Engineering  from Princeton  University and a
masters of  mechanical  engineering  degree and  bachelor  of civil  engineering
degree  from  Clarkson  College  of  Technology.  Dr.  Caporali,  65,  served as
President of Grumman  Corporation's  Aircraft  Systems Division since 1985, Vice
Chairman of Corporate  Technology 1988 to 1990 and Chairman and CEO from 1990 to
June   1994.   Consultant   to  and  member  of  the  board  of   directors   of
Northrop-Grumman  from June 1994 to March 1995. Serves on a Princeton University
Advisory  Council.  Former  Chairman of the Aerospace  Industries  Association's
Board of Governors  and Executive  Committee.  Presently  corporate  Senior Vice
President of  Engineering  and Business  Development  for the Raytheon  Company.
Member of the National Academy of Engineering.

Katherine D.  Ortega:  Director of LILCO since 1993.  Received  bachelor of arts
degree in business and economics  from Eastern New Mexico  University  and three
honorary doctor of law


                                       99

<PAGE>

degrees and an honorary doctor of social science degree.  Ms. Ortega, 63, served
as Treasurer of the United States from 1983 to 1989. Served as a commissioner of
the Copyright Royalty Tribunal,  a member of the President's  Advisory Committee
on Small and Minority  Business and an  alternate  representative  to the United
Nations General  Assembly.  Member of the board of directors of Ultramar Diamond
Shamrock Corporation,  The Kroger Company, Ralston Purina Company, Rayonier Inc.
and Catalyst.  Member of the Comptroller  General's  Consultant Panel.  Advisory
Board Member of Washington Mutual Investors Fund.

Vicki L.  Fuller:  Director of LILCO since 1994.  Received  bachelors  degree at
Roosevelt  University  and  masters  degree in  business  administration  at the
University of Chicago and is a Certified  Public  Accountant.  Ms.  Fuller,  41,
served as an associate in Morgan Stanley and Co.'s corporate finance  department
from 1981 to 1983.  Served as a rating officer at Standard & Poor's  Corporation
from 1984 to 1985. Joined Equitable Capital  Management  Corporation  ("ECM") in
1985  as a  senior  investment  manager,  holding  various  positions  including
Managing  Director  from  1989 to  1993.  Vice  President  of  Alliance  Capital
Management  Corporation  ("Alliance"),  which  acquired  ECM, from 1993 to 1994;
currently holds the position of Senior Vice President of Alliance. In compliance
with Section  305(b) of the Federal Power Act, Ms. Fuller has  authorization  to
hold the position of an officer or director of a public  utility and at the same
time the  position  of an officer or director  of a firm that is  authorized  to
underwrite  or  participate  in the  marketing  of the  securities  of a  public
utility.

James T. Flynn: Appointed by the Board of Directors, Mr. Flynn became a Director
in December 1996.  Holds a bachelor of science degree in mechanical  engineering
from Bucknell University and is a Licensed Professional  Engineer.  Joined LILCO
in October 1986 as Vice President of Fossil Production and was promoted to Group
Vice President,  Engineering and Operations in April 1992.  Appointed  Executive
Vice President and Chief  Operating  Officer in March 1994.  Mr. Flynn,  64, has
served as President and Chief Operating Officer since December 1996.

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.

Compliance with Section 16(a) of the Exchange Act

LILCO is required to identify  any  Director,  Officer,  or person who owns more
than ten percent of a class of equity  securities who failed to timely file with
the Securities and Exchange Commission (the "SEC") a required report relating to
ownership  and  changes in  ownership  of LILCO's  equity  securities.  Based on
information  provided to LILCO by such persons, all LILCO Officers and Directors
made all required  filings  during the fiscal year ended March 31,  1998.  LILCO
does not know of any  person  beneficially  owning  more  than 10% of a class of
equity securities.


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<PAGE>

Item 11.   Executive Compensation

Compensation Paid to Directors

The annual  retainer fee paid to each Director  during the prior fiscal year was
$12,500 in cash and $12,500 applied to a deferred stock unit account, except for
Dr.  Catacosinos  and Mr.  Flynn  who,  as  Officers  of LILCO,  do not  receive
compensation for serving as Directors.  The fee paid to each Director who is not
also an Officer of LILCO for attending each meeting of the Board of Directors or
of one of its committees was $500.

Under  the terms of the  Directors'  Stock  Unit  Retainer  Plan (the  "Retainer
Plan"), each non-employee director of LILCO is required to apply at least 50% of
his or her  annual  retainer  to the  purchase  of Common  Stock  units  ("Stock
Units").   Allocation   of  Stock  Units  under  the  Retainer   Plan  are  made
automatically  on the date  during each  fiscal  quarter on which the  quarterly
installment of the annual retainer is paid.

Under the Retainer  Plan,  the value of the units which will be credited to each
non-employee  Director's  account on a  quarterly  basis will be  determined  by
dividing the  aggregate  amount of cash  credited to such account by the closing
price per share of LILCO Common Stock,  as reported on a New York Stock Exchange
listing of  composite  transactions,  on the first  trading day of the  calendar
month in which the  Participant's  retainer  is paid.  The  amounts  accumulated
pursuant to the Retainer  Plan will be held until such time as (i) a participant
ceases to serve as a  Director  or  Consulting  Director;  (ii) a  participant's
death; or (iii) a "Change in Control" (as defined in the Retainer Plan).

If the Director so elects,  the aggregate  value of the Stock Units  accumulated
pursuant to the Retainer  Plan may be received in  certificated  shares of LILCO
Common  Stock at the time of  distribution.  The Director may elect to receive a
distribution  of  Retainer  Plan  benefits  in a  lump  sum  or  in  ten  annual
installments.  Any such shares shall be purchased by LILCO on the open market or
shall be taken from shares of Common Stock previously acquired by LILCO and held
in its treasury. Prior to distribution, a Director shall have no voting or other
rights  of a  shareholder  with  respect  to such  Stock  Units.  However,  each
Director's  account  will be credited  with an amount equal to the amount of any
dividends  paid on shares of LILCO Common Stock  proportionate  to the number of
Stock Units  accumulated  pursuant to the Retainer  Plan prior to such  dividend
payment  date.  Amounts so credited  shall be applied  toward the purchase of an
additional  number of Stock Units.  The transactions  contemplated  with KeySpan
and/or  LIPA will result in a Change in Control  for  purposes  of the  Retainer
Plan.

LILCO has  entered  into a  consulting  agreement  with Eben W.  Pyne,  a former
Director of LILCO, naming him Consulting Director.  This agreement provides that
the  Consulting  Director  will  advise  and  counsel  the  Board and any of its
committees  on various  matters and will  receive an annual  retainer of $25,000
(half of which was  credited to a deferred  stock unit  account  pursuant to the
Retainer  Plan as  discussed  above) plus an  additional  $500 for each Board or
committee  meeting  attended.  A Consulting  Director does not have the right to
vote at meetings of the Board or at meetings of committees of the Board.

Directors  may elect to defer the receipt of any  portion of their  compensation
under the Deferred  Compensation  Plan for  Directors.  Amounts  deferred may be
allocated to a deferred


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<PAGE>

compensation  account.  Each participating  Director's account accrues interest,
compounded  quarterly,  at the prime rates plus 1/2%. The Deferred  Compensation
Plan for  Directors is unfunded and any accounts  under the plan will be general
obligations  of  LILCO.  Distributions  from  a  deferred  compensation  account
commence upon  termination  of  membership  on the Board of Directors,  death or
disability,  or at a date  previously  designed by the  participating  Director.
Distributions  from the  deferred  compensation  account may be made by lump-sum
payment or annually over either a five or ten-year period. Currently none of the
Directors are participating in the Deferred Compensation Plan for Directors. The
Deferred Compensation will be terminated  immediately prior to the completion of
the transactions contemplated with KeySpan and/or LIPA.

LILCO has a Retirement  Plan for Directors (the  "Retirement  Plan"),  providing
benefits  to  Directors  who are not or who  have not been  Officers  of  LILCO.
Directors  who have served in that  capacity for more than five years qualify as
participants  under the plan.  The plan provides for a monthly  benefit equal to
one-twelfth  of the highest  annual  retainer paid to each  participant.  A full
benefit is available for  participants  who serve for ten years with a reduction
of one-sixtieth  for each month of service less than ten years.  Under the plan,
payment of benefits is to begin when the Director  ceases to serve as a Director
or  Consulting  Director or reaches age 65,  whichever  is later.  The plan also
provides  that  in the  event  of a  "change  in  control"  (as  defined  in the
Retirement  Plan),  including by virtue of an  acquisition  of LILCO's assets or
stock, the value of vested benefits could be payable immediately. In addition to
Directors  Barnes,  Bugliarello,  Caporali,  Ortega and Schmalensee who would be
entitled  to be paid a reduced  benefit,  Directors  Paterson,  Talmage and Pyne
would be  entitled  to be paid  full  benefits  were they to cease to serve as a
Consulting  Director  or  Director  at this time.  Benefits  are  provided  on a
straight-life  annuity  basis except that if the Director is married at the time
benefits  begin, a joint and 50% survivor  benefit may be paid on an actuarially
equivalent  basis.  The benefits are  unfunded  and are general  obligations  of
LILCO. The transactions  contemplated  with KeySpan and/or LIPA will result in a
Change in Control for purposes of the Retirement  Plan and such  Retirement Plan
will be terminated immediately prior to the close of these transactions.

LILCO  entered  into an  agreement  in 1987  with Mr.  Sideris,  while he was an
Officer of LILCO, which provides retirement benefits  supplementing the benefits
to which he is entitled under LILCO's  Retirement  Income Plan and  Supplemental
Death and Retirement  Benefits Plan, both discussed below. LILCO has established
a  trust,  which  is  currently  making  payment  of  the  retirement  benefits.
Notwithstanding  the  creation of the trust,  LILCO  continues  to be  primarily
liable.

Pursuant to the New York Business  Corporation Law and LILCO By-laws,  LILCO has
entered  into  agreements   with  its  Directors  and  Officers   providing  for
indemnification  and  advancement  of expenses in defending  certain  actions or
proceedings in advance of their final disposition  subject to refund if they are
found not to be entitled to indemnification.  LILCO has established a trust, the
Long Island Lighting Company Officers' and Directors'  Protective Trust, to fund
LILCO's obligations under these agreements.


                                       102

<PAGE>

Report of the Compensation and Management
Appraisal Committee on Executive Compensation

The  disclosure  contained  in this section of the Form 10-K shall not be deemed
incorporated  by  reference  into any  prior  filing  by LILCO  pursuant  to the
Securities Act of 1933 or the Securities  Exchange Act of 1934 that  incorporate
future filings or portions thereof (including this Form 10-K or any amendment or
any part thereof).

The Compensation and Management  Appraisal  Committee (the  "Committee"),  which
establishes  the  procedures by which  management  compensation  is  determined,
reviews and  recommends  to the Board of Directors  the  compensation  levels of
LILCO's  officers and administers the Annual Stock Incentive  Compensation  Plan
(the  "Annual  Stock  Incentive  Plan") and the  Long-Term  Incentive  Plan (the
"Long-Term  Incentive  Plan") discussed below. The Committee is made up entirely
of outside  Directors.  Its members  are George  Bugliarello,  A. James  Barnes,
Richard L. Schmalensee and John H. Talmage.

During 1997, the Committee used two outside  consultants,  the Hay Group ("Hay")
and William M. Mercer,  Inc.  ("Mercer"),  to review the compensation  levels of
LILCO's officers,  including the named executive officers, and to provide advice
with respect to incentive  compensation  arrangements.  LILCO's Human  Resources
office also supplied industry compensation comparisons.

Executive Compensation Philosophy

It  is  the  Board's   philosophy   to  use   incentives   and  other   variable
performance-based  pay programs to link executive pay with enhancements to LILCO
performance  and customer  service and to ensure the  attraction,  retention and
motivation of key executives.  In order to keep pace with industry  practice and
accomplish  these  objectives,  the Board  adopted  the Annual  Stock  Incentive
Program in 1995 and  adopted  the  Long-Term  Incentive  Program  in 1996.  Both
incentive  programs  have been  approved  by  common  stock  shareholders.  This
performance-based  compensation  philosophy places a significant emphasis on the
achievement  of  strategic  goals  related to  financial  and  customer  service
performance.  However,  even after the  adoption  of the  Annual  and  Long-Term
Incentive Plans,  data provided to the Committee by Hay and Mercer indicate that
LILCO's officer total compensation opportunities remains significantly below all
competitive market segments,  including other comparable electric utilities,  as
described below.

Determination of Base Salary Levels

In 1997,  the Committee  considered  adjustments to base salary ranges using the
external  comparisons  to other utility and  non-utility  companies as described
below.  Specifically,  the Committee studied the average  compensation levels of
comparable  executives of three databases  provided by Hay for general industry,
metropolitan New York companies and 15 electric and gas stock-issuing utilities.
For CEO  compensation,  Hay also  provided  comparisons  to 37 Standard & Poor's
Utilities.  In addition to  compensation  levels  among the Hay  databases,  the
Committee also reviewed the results of the Edison  Electric  Institute's  Annual
Compensation  Survey  of 85  utilities  (the  "EEI  Utilities")  as  well as the
compensation  paid to the  officers of ten other  regional  utilities.  Based on
these comparisons and the recommendation of Hay, the Board adopted a


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<PAGE>

philosophy to target base salary ranges at the median of general industry in the
metropolitan New York area.

Individual  base salary  increases  within  those  ranges are then  subjectively
determined based on several factors.  These factors include the  competitiveness
of the executive's current base salary and potential incentive compensation, the
executive's  individual  accomplishments  during  the year  and the  executive's
length of time in his or her position. However, based on data provided by Hay in
December 1997, LILCO base salaries were 4.2 percent below general industry, 11.7
percent  below  metropolitan  New York  companies  and 9.7 percent below the Hay
utility group.

The Annual Stock Incentive Compensation Plan

Annual  incentive  compensation  is earned under LILCO's Annual Stock  Incentive
Plan.  This Plan was adopted in 1995 and  approved by  shareholders  at the 1997
Annual Meeting.  Awards earned under the Plan, less applicable tax  withholding,
are paid in common  stock.  By making the awards  payable in LILCO common stock,
officers'  performance is more closely aligned with shareholder interest. At the
end of 1997,  the Board altered its policy of paying awards in the calendar year
following the year in which they were earned to a policy of paying awards at the
end of the year in which they were earned. Therefore,  officers received payment
in stock for the  performance  achieved in 1997 at the end of December  1997. In
addition,  officers  received  payment  at that time of awards  for  performance
earned in 1996.

The Annual Stock Incentive Plan is based on the achievement of two  quantifiable
objectives:  reducing expenditures and maintaining or improving critical service
goals. If threshold levels are not achieved for either  objective,  no incentive
is earned.  As threshold  levels are exceeded,  the officers  become eligible to
receive awards from the Annual Stock Incentive Plan.

For 1998,  target  incentive  awards - the  amounts  earned if goal  performance
levels are  attained  for all program  objectives - are 60% for the CEO, 50% for
the COO, 35% for senior officers and 20% for other  officers,  of the greater of
their base salary or the midpoint of the base salary range for each participant.
For 1997, target incentive awards were 45% for the CEO, 30% for the COO, 20% for
senior officers and 15% for other officers.  For 1996,  target  incentive awards
were 45% for the CEO, 25% for the COO, 15% for senior officers and 10% for other
officers.  The  midpoint  for the  base  salary  range  is  dependent  upon  the
executive's level in the organization. Seventy-five percent of each individual's
earned incentive award is based on the level of achievement of the two corporate
objectives.  The balance of each award,  which can range from zero to 50 percent
of the earned incentive award, is then subjectively  determined by the Committee
based  on each  individual's  contribution  toward  helping  LILCO  achieve  its
objectives.  Based on the level of achievement for the increase in net cash flow
and service  goals,  and  individual  contributions  to LILCO,  awards under the
Annual Stock Incentive Plan paid in 1997 for plan year 1997 and 1996 ranged from
75 to 112 percent and from 75 to 124 percent, respectively, of each individual's
earned incentive award. As a result of the closing of the KeySpan Transaction at
the end of May 1998, both KeySpan and LILCO  terminated  their Annual  Incentive
Plans.  LILCO pro-rated its target goals so that 5/12ths of the earned incentive
was made based on the results achieved to date. For 1998, all participants  were
paid 100 percent of their pro-rated individual earned incentive.


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<PAGE>

The Officer Long-term Incentive Plan

In December  1995,  LILCO's Board of Directors  adopted,  and at the 1996 Annual
Meeting the shareholders  approved, the Long-Term Incentive Plan. The purpose of
the  Long-Term  Incentive  Plan is to  motivate  the  Officers to meet or exceed
LILCO's  business  goals,  with a particular  focus on the long-term  effects of
their actions, and to provide incentives for continued service to LILCO.

Awards made under the Long-Term Incentive Plan are paid only upon the attainment
of  financial  performance  goals  or  goals  set by the  Committee.  The  first
Performance Period was for two years (1996-1997) and the goals included freezing
rates,  improving earnings and reducing operating and maintenance  expenditures.
Subsequent  Performance  Periods were to include  goals to be attained  over the
period of three calendar years,  with a new cycle beginning every two years (the
"Performance  Period").   Awards  are  paid  for  the  attainment  of  specified
threshold,  target and maximum  results  over the  Performance  Period and are a
specified percentage per year of the greater of the participant's base salary or
midpoint  of that  individual  participant's  salary  range.  For the  1996-1997
Performance  Period,  the  maximum  award  of 125% of each  participants  target
incentive award was earned.

Originally,  the  Plan was  designed  so that  the  awards  would be paid in two
installments,  each of which could be paid in shares of Common  Stock.  However,
following  the  completion  of the first cycle at the end of 1997 and due to the
anticipated closing of the KeySpan Transaction during 1998, the Board determined
to award the full amounts for the 1996-97  cycle to all  officers.  In addition,
similar to the Annual Stock Incentive Plan and as a result of the closing of the
KeySpan  Transaction at the end of May 1998,  both KeySpan and LILCO  terminated
their  Long-Term  Incentive  Plans.  LILCO  pro-rated  its target  goals so that
17/36ths of the earned  incentive award for the 1997-99  Performance  Period was
made. All goals for this period achieved their maximum levels and, thus, 125% of
each participant's target incentive award was earned.

Special Performance Incentives

During  1997,  the Board  authorized  special  performance  incentives  to seven
officers,  including four of the named officers in the  Compensation  table,  in
recognition of the efforts of these  individuals in connection  with the KeySpan
Transaction  and the LIPA  Transaction.  The amount of the  awards  were paid in
shares of common stock, net of appropriate employment tax withholdings, and were
based on a percentage  of the greater of base salary or the midpoint of the base
salary range for each participant. Awards related to the LIPA Transaction ranged
from 5 percent to 20  percent,  and for the  KeySpan  Transaction  ranged from 5
percent to 25 percent,  based on each individual's  contribution and involvement
in one or both of the transactions.

Transaction-Related Actions

In order to reduce the risk of loosing key executives during the critical period
of  planning  for  the   consummation  of  the  KeySpan   Transaction  and  LIPA
Transactions,  the Company  entered  into  Retention  Agreements  with  eligible
officers,  except the CEO and COO, for a one-year  period  commencing July 1997.
These Agreements provided an incentive of 20 percent of the greater of


                                       105

<PAGE>

each  participant's  base salary or the  midpoint  of the base salary  range for
continued employment throughout the period of the Agreement.

In addition,  payments  were made of benefits  previously  accrued by executives
under  plans and  programs  which are not to be  continued  by the new  combined
entity.

Finally,  because the payments of the  pro-rated  1998 Annual  Incentive and the
1997-1999  Long-term Incentive were made immediately prior to the closing of the
two  transactions,  these awards were  authorized to be paid in cash rather than
stock for administrative simplicity prior to the share exchange and delisting of
LILCO's Common Stock.

CEO Compensation

Coming into 1997, Dr.  Catacosinos'  base salary had been held at its March 1995
level  in  order to  transition  to  incentive-based  compensation  through  the
introduction  of the Annual  Stock and  Long-Term  Incentive  Plans.  Therefore,
during  1997,  the Board  twice,  in January  and in  December,  considered  Dr.
Catacosinos'  base salary level.  Each time the Board considered the competitive
market, Dr.  Catacosinos's  tenure as CEO and the performance  factors described
below. Based on these factors,  Dr. Catacosinos' base salary was increased by 14
percent in February 1997 and by 5.7 percent in December 1997.

In authorizing  the February  increase in base salary for Dr.  Catacosinos,  the
Board  considered the Company's  performance  during 1996.  Throughout 1996, the
Company  continued to pursue its  aggressive  program to contain  operating  and
maintenance  expenses as well as capital expenses.  As a result,  budget targets
were  underrun by 5.6 percent and earnings  increased  by 4 cents per share.  In
addition,  positive  net cash flow of $241  million was achieved and the Company
was able to use $415  million of cash to satisfy its  obligation  regarding  G&R
bonds that matured. The debt to equity ratio continued to improve, dropping from
61.8  to  59.3  percent.  In  addition,  at the  end of  1996  the  Company  had
successfully  negotiated a merger agreement with Brooklyn Union that is expected
to result in significant synergy savings to the combined entity and enhance such
entity's competitive position.

In authorizing  the December  increase in base salary for Dr.  Catacosinos,  the
Board considered the Company's performance and achievements during 1997. Notably
in 1997, the Company  negotiated the LIPA Transaction that would enable electric
rates to be reduced by  approximately  20 percent and  included  the purchase by
LIPA, in a stock  transaction,  of the electric  transmission  and  distribution
system, the Company's 18 percent interest in the Nine Mile Point 2 nuclear plant
and the Company's  electric  regulatory  assets.  In addition during 1997, while
planning for the consummation of the KeySpan  Transaction and LIPA  Transaction,
the  Company   was  also  able  to  achieve   significant   financial   results.
Specifically,  earnings per share increased by 13 cents per share. Net cash flow
of $187  million was  achieved.  The Company was able to use cash to redeem $252
million of maturing debt, reducing the debt to equity ratio to 57.5 percent.

In making its  determination  with  respect  to Dr.  Catacosinos'  Annual  Stock
Incentive  Plan  award for plan year 1996,  the Board  considered,  among  other
things,  the level of  achievement of the budget and service goals in accordance
with the Annual Stock Incentive Plan and the period of


                                       106

<PAGE>

time from the earning of the  incentive to the  granting of the award.  Based on
these achievements, the Board approved an incentive award for Dr. Catacosinos of
10,535  shares  of LILCO  common  stock.  For  1997,  based on the level of goal
achievement, Dr. Catacosinos was awarded 8,351 shares of common stock. Awards of
shares of common stock for 1996 and 1997 were net of the appropriate  income and
employment taxes. For the 1998 pro-rated incentive, Dr.
Catacosinos was granted an award of $218,750.

With  respect to Dr.  Catacosinos'  1996-97  Long-term  Incentive,  based on the
results  achieved,  the Board granted an award of 17,164 shares of Common Stock,
net of  appropriate  income and  employment  taxes.  For the  1997-99  pro-rated
Performance  Period,  an award of  $743,750  was  granted  based on the  results
achieved.

Hay's  market  comparisons  in 1997 showed that Dr.  Catacosinos'  total  direct
compensation  was 21.5  percent  below  general  industry,  25.3  percent  below
metropolitan  New York companies and 27.4 below the Hay utility group.  However,
by establishing  direct links between  performance and both direct and long-term
compensation, the Committee believes that LILCO's compensation programs properly
align  management's  interests  with the long-term  interests of ratepayers  and
shareholders.

Certain Tax Matters

Generally,  Section  162(m) of the  Internal  Revenue  Code of 1986,  as amended
limits tax deductions for executive  compensation to $1 million.  However, since
LILCO will have no publicly traded equity  securities at the end of its 1998 tax
year, Section 162(m) does not apply.

                                  George Bugliarello -- Chairman
                                  John H. Talmage
                                  A. James Barnes
                                  Richard L. Schmalensee


Stock Performance Graph

Set forth  below is a graph  comparing  the  cumulative  return  of  LILCO,  the
Standard & Poor's 500  Composite  Stock Index  ("S&P 500") and the S&P  Electric
Utilities  Index ("S&P ELEC") over the  preceding  five fiscal years  commencing
with  fiscal  year  ended  March  31,  1993.  The graph  assumes a $100  initial
investment on March 31, 1993, and a reinvestment  of dividends in LILCO and each
of the companies reported in the indices.

                 LILCO                   S&P 500                   S&P ELEC

1993             $ 100                   $ 100                     $ 100
1994                84                     101                        90
1995                63                     117                        93
1996                85                     155                       113
1997               127                     186                       112
1998               177                     275                       155


                                       107

<PAGE>


                                                     PRIVILEGED AND CONFIDENTIAL
                                                   ATTORNEY-CLIENT COMMUNICATION

Compensation Paid to Executive Officers
Summary  Compensation  Table:  In March 1997,  the Board of  Directors  voted to
change the Company's fiscal year end from December 31 to March 31 effective with
the  three  month  period  ended  March  31,  1997  (the  "Transition  Period").
Accordingly,  the following table  illustrates the compensation paid by LILCO to
each of its most highly compensated Executive Officers for the fiscal year ended
March 31, 1998 and for the fiscal years ended  December 31, 1996 and 1995.  Also
included is certain compensation earned during fiscal 1998.



<TABLE>
<CAPTION>
                                                  Annual Compensation                 Long Term Compensation
-----------------------------------------------------------------------------------------------------------------------------------
                                                                   Other      Restricted                  Payouts-
                                                                   Annual      Stock         Options/      LTIP        All Other
       Name and Principal                Salary      Bonus     Compensation    Award(s)($)     SARs (#)    Payouts     Compensation
            Position          Year      ($)(1)(2)     ($)(3)        ($)                                    ($)(4)         ($)(5)
-----------------------------------------------------------------------------------------------------------------------------------
<S>                          <C>  <C>   <C>         <C>                                                   <C>             <C>   
William J. Catacosinos -     1997/98    673,333(6)  1,202,972        n/a         n/a            n/a       742,500         23,241
CEO                          1996       580,413(6)   153,203         n/a         n/a            n/a         n/a           18,653
                             1995       587,976(6)       0           n/a         n/a            n/a         n/a           15,184
-----------------------------------------------------------------------------------------------------------------------------------
James T. Flynn - COO and     1997/98     310,000     408,956         n/a         n/a            n/a       294,362         8,300
President                    1996        263,364      90,554         n/a         n/a            n/a         n/a           5,800
                             1995        255,500         0           n/a         n/a            n/a         n/a           3,725
-----------------------------------------------------------------------------------------------------------------------------------
Leonard P. Novello -         1997/98     258,335     211,458         n/a         n/a            n/a       125,000         1,753
Senior Vice President        1996        236,186      33,693         n/a         n/a            n/a         n/a           1,410
and General Counsel          1995       176,250(7)       0           n/a         n/a            n/a         n/a             883
-----------------------------------------------------------------------------------------------------------------------------------
Michael E. Bray -            1997/98    254,334(8)    62,500         n/a         n/a            n/a          0             738
Senior Vice President -      1996           0            0           n/a         n/a            n/a         n/a            n/a
Electric Business Unit       1995           0            0           n/a         n/a            n/a         n/a            n/a
-----------------------------------------------------------------------------------------------------------------------------------
Adam M. Madsen -             1997/98     198,666     133,945         n/a         n/a            n/a        96,196          833
Senior Vice President -      1996        172,166      15,826         n/a         n/a            n/a         n/a            1,392
Corporate and Strategic      1995        162,000         0           n/a         n/a            n/a         n/a           1,205
Planning
=================================================================================================================================
</TABLE>
 * n/a - Not Applicable.


                                       108

<PAGE>

Notes to Summary Compensation Table:

(1)  During the Transition Period, Dr. Catacosinos,  Mr. Flynn, Mr. Novello, and
     Mr. Madsen received salary payments of $133,234, $75,000, $62,083, $43,000,
     respectively.  As  discussed  below,  Mr.  Bray was not an  employee of the
     Company during the Transition Period.

(2)  LILCO has in place a 401(k) Capital  Accumulation Plan, which qualifies for
     favorable  tax  treatment  under  the  Internal  Revenue  Code of 1986,  as
     amended.   This  plan  is  designed   to  provide   for  salary   reduction
     contributions by participants  under Section 401(k) of the Internal Revenue
     Code of 1986, as amended that permit  employees to defer a portion of their
     current  compensation and therefore a portion of their current federal and,
     in most instances,  state and local income taxes. Although this plan allows
     LILCO to make matching  contributions  to these deferred  amounts,  no such
     matching contributions have been made to date. The amounts shown for annual
     salary  in the  Summary  Compensation  Table  for each  individual  officer
     include amounts deferred by those individuals into this plan.

(3)  Represents  (i) the dollar  value of LILCO  Common  Stock  awards under the
     Annual Stock  Incentive  Plan for plan years 1996 (other than for Mr. Bray)
     and  1997,  including  applicable  tax  withholdings  and  (ii)  awards  in
     connection  with the  LIPA and  KeySpan  transactions  (other  than for Mr.
     Bray).  The net amount of these  awards  were  primarily  paid in shares of
     LILCO Common Stock as follows: Dr. Catacosinos - 27,081 shares, Mr. Flynn -
     8,976 shares,  Mr. Novello - 4,533 shares, Mr. Bray - 1,406 shares, and Mr.
     Madsen - 3,013  shares.  For the 1998 plan year,  pro rata  amounts will be
     paid  in  cash   immediately   prior  to  completion  of  the  transactions
     contemplated with KeySpan and LIPA as follows:  Dr. Catacosinos - $218,750,
     Mr. Flynn - $109,354,  Mr. Novello - $50,130,  Mr. Bray - $48,998,  and Mr.
     Madsen - $38,646.

(4)  Represents  the dollar  value of LILCO  Common  Stock awards under the Long
     Term  Incentive  Plan for plan years  1996-1997,  including  applicable tax
     withholdings.  The net  amount of the  awards  were paid in shares of LILCO
     Common Stock as follows:  Dr.  Catacosinos - 16,703, Mr. Flynn - 6,621, Mr.
     Novello  - 2,812,  Mr.  Madsen - 2,164.  For the 1998 plan  year,  pro rata
     amounts  will be  paid  in cash  immediately  prior  to  completion  of the
     transactions contemplated with KeySpan and LIPA as follows: Dr. Catacosinos
     - $743,150,  Mr.  Flynn -  $371,803,  Mr.  Novello -  $170,442,  Mr. Bray -
     $166,593, and Mr. Madsen - $131,395.

(5)  LILCO has a noncontributory Supplemental Death and Retirement Benefits Plan
     for its Officers and certain other senior management employees.  Currently,
     death benefits for the Chairman, CEO, President and Chief Operating Officer
     ("COO") are five times their plan compensation and, for each other Officer,
     three  times  their  plan  compensation.  Compensation  under  this plan is
     defined as the highest salary  including any incentive  earned  pursuant to
     the Annual Stock Incentive Plan. The cost of life insurance,  paid by LILCO
     for coverage  under this plan,  is included in All Other  Compensation  for
     each of the individuals listed. For each year reflected in the Compensation
     Table,  insurance  coverage  for  these  death  benefits  was  provided  by
     split-dollar life insurance  policies on the life of each plan participant.
     The amount shown for each  participant  represents the amount  allocated to
     such participant for income tax purposes.

(6)  A  portion  of Dr.  Catacosinos'  salary  in each of these  years  has been
     deferred at his request and is reflected in the amounts shown.

(7)  Leonard P. Novello  assumed duties as General  Counsel  effective  April 1,
     1995.  Prior to that date, Mr.  Novello was General  Counsel for the public
     accounting firm of KPMG Peat Marwick.

(8)  Michael E. Bray  assumed  the duties of Senior  Vice  President  - Electric
     Business Unit  effective  March 1, 1997.  Prior to that date,  Mr. Bray was
     President and CEO of DB Riley Consolidated.


                                      109

<PAGE>

Supplemental  Death and  Retirement  Benefits  Plan:  Officers and certain other
senior  management  employees  eligible to participate  in LILCO's  Supplemental
Death and Retirement  Benefits Plan are provided with death benefits,  generally
funded by life  insurance,  equal to five  times the plan  compensation  for the
Chairman,  CEO, President and COO and three times the plan compensation for each
other Officer. "Plan compensation" is defined in this plan as the highest annual
rate of pay consisting of (i) the highest rate of base pay in effect at any time
and (ii) a  single  incentive  benefit  payment  pursuant  to the  annual  stock
incentive  plan.  Prior to  retirement,  participants  elect  either to  receive
continued death benefit coverage or to receive monthly  retirement  benefits,  a
partial lump-sum  distribution,  or a combination of each. For a participant who
retires  on or after age 65 and  elects  the death  benefit,  the death  benefit
coverage will be continued up to five times plan  compensation for the Chairman,
CEO, President and COO and up to three times plan compensation for each Officer.
For a  participant  who  retires  on or  after  age 65 and  elects  the  monthly
retirement  income benefit,  the annual  retirement  benefits  payable under the
15-year certain option will be, for the Chairman, CEO, President and COO, 25% of
plan  compensation  and,  for each other  Officer,  15% of such  Officer's  plan
compensation,  with other  options  available to make payment on an  actuarially
equivalent basis through a lifetime annuity,  a joint and survivor annuity or an
increasing income annuity. Retirement benefits under this plan are not available
to  participants  who retire prior to age 60. A  participant  will vest upon the
earlier of attainment of age 60 with ten years of service or upon  attainment of
his or her  normal  retirement  date  (i.e.,  age 65).  If a vested  participant
retires  prior  to age 65,  reduced  benefits  are  payable.  The  terms  of Dr.
Catacosinos'  employment  agreement,  discussed below, provide for his continued
employment beyond normal retirement age.

In contemplation of the  consummation of the KeySpan  transaction,  the Board of
Directors  determined,  for various reasons, to discontinue future participation
in the plan and to make payments of the accrued  retirement  benefits  under it.
The projected annual pension  assuming payment on May 28, 1998,  pursuant to the
Supplemental  Death and  Retirement  Benefits  Plan  considering  the  Change of
Control provisions in the Executive Employment Agreements with each officer, are
as follows: Mr. Flynn, $125,444; Mr. Novello, $16,099; Mr. Bray, $2,658; and Mr.
Madsen, $38,069.  Accordingly, each officer received, pursuant to Board actions,
a benefit representing the present value of the projected annual amounts earned.
Pursuant  to the terms of the plan,  Dr.  Catacosinos  would be  entitled  to an
annual  retirement  benefit,  however,  because  Dr.  Catacosinos  has  made  an
assignment of his rights to death  benefits,  he did not receive any  retirement
income benefits under this plan.

LILCO  recognized the cost of all benefits  provided under the Plan,  which were
borne by LILCO's shareholders,  as an expense on its income statement. LILCO has
also  established a trust to provide for payments of its  obligations to retired
participants   in  the   Supplemental   Death  and  Retirement   Benefits  Plan.
Notwithstanding  the  creation of the trust,  LILCO  continues  to be  primarily
liable for both the death and retirement  benefits  payable to the  participants
and is currently making payments to retired participants.


Retirement  Income Plan:  Generally,  all LILCO employees (except certain leased
and part-time  employees)  are eligible for inclusion in the  Retirement  Income
Plan upon completion of one year

                                      110

<PAGE>



of employment with LILCO. A participant  will vest upon completion of five years
of service.  This plan is currently  noncontributory  and provides  fixed-dollar
pension benefits.

The  Retirement  Income Plan uses a career  average pay formula which provides a
credit for each year of participation in the retirement plan. For service before
January 1, 1992,  pension  benefits are  determined  based on the greater of the
accrued  benefit as of December 31, 1991, or by  multiplying a moving  five-year
average of plan  compensation,  not to exceed the January 1, 1992  salary,  by a
certain  percentage  determined by years of participation in the retirement plan
at December 31, 1991.  For service after January 1, 1992,  pension  benefits are
equal to 2% of "plan compensation"  through age 49 and 2 1/2% thereafter.  "Plan
compensation"  is  defined  in this  plan as the base  rate of pay in  effect on
January  1 of each  year and may  differ  from the  amounts  reported  under the
heading "Salary" in the Summary  Compensation Table. Any difference is primarily
attributable  to the timing of annual salary  increases for the named  executive
officers  which impacts the amount paid to such officer and reported for a given
year.

The following table shows the projected annual  retirement  benefit payable on a
straight-life  annuity basis pursuant to LILCO's  Retirement Income Plan to each
of the individuals listed in the Summary Compensation Table at normal retirement
age  (which  is  the  later  of age  65 or  five  years  of  service),  assuming
continuation  of  employment  to  normal  retirement  date  at the  rate of plan
compensation during fiscal 1998:

<TABLE>
<CAPTION>
                                    Annual                           Credited                 Normal
                                     Retirement                      Service as              Retirement
                                     Benefit(1)                      of 3/31/97                 Date
------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                         <C>                       <C>       
William J. Catacosinos               $196,452                    14 years, 2 months        April 1, 1995(2)
James T. Flynn                       $ 68,353                    11 years, 6 months        January 1, 1999
Leonard P. Novello                   $ 24,333                     3 years, 0 months        December 1, 2005
Michael E. Bray                      $ 10,080                     1 year, 1 month          June 1, 2012
Adam M. Madsen                       $ 82,935                    30 years, 3 months        August 1, 2001
</TABLE>


(1) These  Retirement  Income Plan  benefits may be limited at retirement by the
maximum  benefit  limitation  under  Section  415  or the  maximum  compensation
limitation  under Section  401(a)(17) of the Internal Revenue Code. The benefits
shown have been calculated  without the  limitations.  LILCO has established the
Retirement  Income  Restoration  Plan of Long Island Lighting Company to restore
qualified  plan benefits  which have been reduced  pursuant to the Code or which
may not be  includible  in the  calculation  of  benefits  pursuant  to  LILCO's
Retirement Income Plan. "Plan  compensation" is defined in the Retirement Income
Restoration  Plan,  as the  highest  annual  rate of pay  consisting  of (i) the
highest  rate of base pay in  effect  at any  time  and (ii) a single  incentive
benefit  payment  pursuant to the annual stock incentive plan. In the event that
the  retirement  benefits  are  reduced by  operation  of either  Section 415 or
401(a)(17) of the Internal Revenue Code,  LILCO's  Retirement Income Restoration
Plan would provide payment of plan formula  pension  benefits which exceed those
payable under the Code's  maximum  limitations.  For 1997,  the maximum  benefit
limit set by Section 415 and applicable to the amounts shown above was $125,000.
For  1997,  the  maximum  compensation  limit  set  by  Section  401(a)(17)  and
applicable  to the  amounts  shown  above was  $160,000.  For 1998,  the maximum
benefit limit set by Section 415 is $130,000 and the maximum  compensation limit
set by Section  401(a)(17)  and to be utilized for  benefits  accrued in 1998 is
$160,000.  Because the Supplemental  Plan retirement  benefits were paid through
March 31, 1998, any retirement benefit  adjustments  payable to the officers are
to be


                                       111

<PAGE>


     made from the Retirement  Income  Restoration Plan immediately prior to the
     completion of the transactions contemplated with KeySpan and/or LIPA.

(2)  Dr. Catacosinos'  employment  agreement,  discussed below, provides for his
     continued employment beyond his normal retirement date.


Agreements  with  Executives:  LILCO  has  entered  into  individual  employment
agreements  with each of its Officers to provide them with  employment  security
and to minimize distractions  resulting from personal uncertainties and risks of
a change in control of LILCO.  Currently,  the  principal  benefits  under these
agreements,  payable if the Officer's  employment  is terminated  for any reason
(including voluntary  resignation) within three years of a change in control (as
defined in these  agreements),  including by virtue of an acquisition of LILCO's
assets or stock,  prior to December 31, 1999,  are: (i)  severance  pay equal to
three  years'  salary;  (ii)  accelerated  vesting  and  payment of the value of
supplemental  retirement benefits at the time of a change in control,  which are
enhanced by three  years of service;  (iii)  continuation  of life,  medical and
dental  insurance for a period of three years;  (iv) gross up of any tax payable
pursuant to the Internal  Revenue Code amended.  The costs associated with these
arrangements will be borne by LILCO's shareholders. Notwithstanding the creation
of a trust to support payment of its obligations,  LILCO is primarily liable for
the compensation  and retirement  benefits payable to the Officers and the trust
will make such payments only to the extent that LILCO does not. The transactions
contemplated  with  KeySpan  and/or  LIPA will result in a change in control (as
defined in these  agreements)  and entitle each Officer to the benefits  payable
under the terms of the  employment  agreements if such  Officer's  employment is
terminated for any reason.

LILCO has also entered into individual employment agreements with certain of its
officers (not including Dr. Catacosinos and Mr. Flynn),  effective July 1, 1997,
pursuant  to which  such  officers  are  employed  for a one  year  term and are
entitled to receive a  retention  bonus equal to 20% of the greater of job value
or salary,  if they are still  employed by LILCO or its affiliates at the end of
such term or are terminated  without cause (as determined by the Chief Executive
Officer)  prior to the  expiration  of such  term.  These  agreements  have been
entered into to induce such  officers to continue  their  employment  during the
period prior to the consummation of the LIPA and KeySpan Transactions.

Under the terms of an  employment  contract  dated as of January  30,  1984,  as
amended (the  "Contract"),  Dr.  Catacosinos has agreed to serve as CEO of LILCO
until January 31, 2002. The Contract provides for a five-year  consulting period
following the termination of his employment  (other than,  except after a change
in control,  for cause).  His  consulting  compensation  will be 90% of his base
annual salary at his retirement  during the first two years,  75% of such salary
during the third and fourth years and 50% of such salary  during the fifth year.
The  Contract  also  provides  for   supplemental   disability   benefits.   Dr.
Catacosinos'  employment under the Contract may be terminated by LILCO for cause
or for such other reason as the Board of Directors may, in good faith, determine
to be in the best interests of LILCO and by Dr.  Catacosinos if he determines it
to be in the  best  interests  of  LILCO or for any  reason  after a  change  in
control. The transactions contemplated with KeySpan and/or LIPA will result in a
change in control  under the  Contract.  The Contract  also  provides for vested
Contract Retirement Benefits commencing at the


                                       112

<PAGE>

earlier  of  Dr.  Catacosinos'  retirement  or  death,  payable  monthly  to Dr.
Catacosinos  and  his  wife as a  joint  and  survivor  annuity  with a  minimum
guaranteed  period of ten years or the present  value  thereof as a lum sum on a
change-in-control.  The Contract Retirement Benefits in any year will be reduced
by monthly  benefits  payable under LILCO's other retirement plans payable under
their  normal  retirement  forms.  The benefit will be based upon a formula that
considers his age at retirement, his highest annual salary, the highest bonus he
has  received  and the  length of his  service to LILCO  including  service as a
Director,  employee or consultant. The benefit is also subject to certain annual
cost of living adjustments.  Assuming, for illustrative purposes, his retirement
at May 31, 1998 the amount of the estimated retirement benefit payable under the
Contract to Dr.  Catacosinos  as of May 31, 1998 (assuming  continuation  of his
current salary) would be approximately $2,094,000.  LILCO has established trusts
to provide for  payments of its  obligations  under the  Contract,  the costs of
which are borne by LILCO's  shareholders.  Notwithstanding  the  creation of the
trusts,  LILCO  continues to be primarily  liable for all amounts payable to Dr.
Catacosinos and the trusts will make such payments to the extent that LILCO does
not.

The  Officers  have  also  entered  into  indemnification  agreements  that  are
described below under the heading "Transactions with Management and Others."

No  Director  or  Officer  or  associate  of any  Director  or  Officer  has any
arrangement  with any person with respect to any future  employment  by LILCO or
its affiliates other than those described herein.


Item 12.  Security Ownership of Certain Beneficial Owners and Management

Current Ownership of LILCO Common Stock. The following table shows the number of
shares*  of Common  Stock  beneficially  owned,  as of March 31,  1998,  by each
Director,  certain  Officers,  and by all Directors and Officers as a group. The
percentage of shares held by any one person,  or all Directors and Officers as a
group, does not exceed 1% of all outstanding shares of Common Stock. The address
of each of the Directors and Officers is: c/o Long Island Lighting Company,  175
East Old Country Road, Hicksville, New York 11801.


                                       113

<PAGE>

       Name                                             Number of Shares*

A. James Barnes.....................................................1,893
Michael E. Bray.....................................................1,406
George Bugliarello..................................................2,393
Renso L. Caporali...................................................2,625
William J. Catacosinos.............................................25,442
James T. Flynn.....................................................21,327
Vicki L. Fuller.....................................................1,693
Adam M. Madsen......................................................7,283
Leonard P. Novello..................................................8,534
Katherine D. Ortega.................................................2,264
Basil A. Paterson...................................................2,499
Richard L. Schmalensee..............................................1,493
George J. Sideris...................................................5,271
John H. Talmage.....................................................1,925
Edward J. Youngling.................................................6,269

All Directors and Officers as a group, including
those named above, a total of 32 persons......................... 157,958


         *The number of shares includes whole shares held under LILCO's Investor
         Common Stock Plan. The number also includes shares held or beneficially
         owned by a spouse,  parent or child for which  beneficial  ownership is
         disclaimed for John H. Talmage - 287 shares, and for George Bugliarello
         - 500  shares.  In  addition,  the  number  of  shares  shown  for each
         Director,  other than Dr.  Catacosinos  and Mr. Flynn,  includes  1,393
         LILCO  Common  Stock  units,  which do not confer  any  voting  rights,
         credited pursuant to the Retainer Plan.


                                       114

<PAGE>



The following table sets forth certain information with respect to the shares of
Preferred  Stock and Common  Stock owned by each person known by LILCO to be the
beneficial  owner of more than 5% of such Preferred Stock and Common Stock as of
December 31, 1997.


<TABLE>
<CAPTION>
Title of                                                                                         Percentage
  Class                    Names and Address                                    Owned            of Class

<S>                                                                        <C>                     <C>  
Common Stock               KeySpan Energy Corporation                      23,981,964*             16.6%
                           One MetroTech Center
                           Brooklyn, NY 11201-3850

Common Stock               The Capital Group Companies, Inc.               11,696,700              9.6%
                                         and
                           Capital Research and Management Company
                           333 South Hope Street
                           Los Angeles, CA  90071

Common Stock               John A. Levin & Co., Inc.                         6,861,988             5.7%
                           One Rockefeller Plaza
                           New York, NY 10020
                                         and
                           Baker Fentress & Company
                           200 West Madison Street
                           Chicago, IL 60606
</TABLE>

         *Represents the number of shares that may be purchased  pursuant to the
         Amended and  Restated  LILCO Stock Option  Agreement  filed on June 30,
         1997 as Exhibit B to Registration Statement on Form S-4, No. 333-30353.

         LILCO has not been advised,  nor is it aware, of any additional  shares
         to which anyone has the right to acquire beneficial ownership.


                                       115

<PAGE>

Item 13.  Certain Relationships and Related Transactions

Transactions with Management and Others

Indemnification  of  Directors  and  Officers:  For  many  years  prior to 1986,
statutory  provisions  of  the  New  York  Business  Corporation  Law  permitted
corporations,  including LILCO,  under certain  circumstances in connection with
litigation in which its Directors  and Officers  were  defendants,  to indemnify
them  for,  among  other  things,  judgments,  amounts  paid in  settlement  and
reasonable  expenses.  To reimburse it when it has indemnified its Directors and
Officers, LILCO began in 1970, pursuant to statutory authorization,  to purchase
Director and Officer  ("D&O")  liability  insurance in each year.  D&O liability
insurance also provides  direct payment to LILCO's  Directors and Officers under
certain  circumstances when LILCO has not previously  provided  indemnification.
LILCO  has D&O  liability  insurance  which  it has  purchased  from  Associated
Electric & Gas  Insurance  Services  Ltd.  ("AEGIS"),  Energy  Insurance  Mutual
("EIM"),  Steadfast Insurance Company, A.C.E. Insurance Company and XL Insurance
Company,  all with  the  effective  date of  August  26,  1997.  LILCO  also has
liability  insurance  effective  August 26, 1997  purchased  from AEGIS and EIM,
which provides fiduciary  liability coverage for LILCO, its Directors,  Officers
and employees for any alleged  breach of fiduciary  duty under ERISA.  The total
annual premium for all these coverages was approximately  $1.5 million in fiscal
1998.

The LILCO  By-laws  provide for the mandatory  indemnification  of Directors and
Officers  to the  extent  not  expressly  prohibited  by the New  York  Business
Corporation  Law. In addition,  the Bylaws  authorize  the Board of Directors to
grant indemnity  rights to employees and other agents of LILCO.  Such provisions
are  effective  as to all  claims  for  indemnification,  whether  the  acts  or
omissions  giving  rise to a claim  for  such  indemnification  occurred  or the
expenses  for which  indemnity  is  sought  were  incurred,  before or after the
provisions  of the By-laws were  adopted.  One of the  provisions of the By-laws
authorized the Board of Directors to enter into indemnification  agreements with
any of LILCO's  Directors or Officers  extending rights to  indemnification  and
advancement  of  expenses  to such person to the  fullest  extent  permitted  by
applicable  law.  LILCO has entered into such  agreements,  which are  described
under the heading  "Compensation  Paid to Directors," with each of its Directors
and Officers.  Pursuant to the terms of those  agreements  and the provisions of
the By-laws,  LILCO has also  established  a trust to fund  LILCO's  obligations
under the agreements.

The LILCO Restated Certificate of Incorporation (the "LILCO Certificate") limits
the  personal  liability  of  Directors  for  certain  breaches  of duty in such
capacity  pursuant to provisions of the New York Business  Corporation  Law. The
LILCO  Certificate does not bar litigation  against  Directors but provides that
Directors are still required to defend themselves in litigation in which acts or
omissions to act are alleged for which they might be held  liable.  Furthermore,
the LILCO Certificate  provides protection to Directors only and does not affect
the liability of Officers of LILCO for breaches of the fiduciary  duties of care
and loyalty.


                                     116

<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 the year  ended  March 31,  1998,  the three
               months ended March 31, 1997 and the years ended December 31, 1996
               and 1995.

          Balance Sheet at March 31, 1998 and 1997 and December 31, 1996.


          Statement of Retained Earnings at March 31, 1998 and 1997 and December
               31, 1996 and 1995.


          Statement of  Capitalization  at March 31, 1998 and 1997 and  December
               31, 1996.

          Statement of Cash Flows for the year ended March 31,  1998,  the three
               months ended March 31, 1997 and the years ended December 31, 1996
               and 1995.

          Notes to Financial Statements.

     (2)  List of Financial Statement Schedules

          Valuation and Qualifying Accounts (Schedule II)

     (3)  List of Exhibits


                                      117

<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.

     2(a) Amended and Restated  Agreement  and Plan of Exchange and Merger dated
          June 26, 1997 between The  Brooklyn  Union Gas Company and Long Island
          Lighting  Company  dated  as of June  26,  1997  (filed  as Annex A to
          Registration Statement on Form S-4, No. 333-30353, on June 30, 1997).

     2(b) Amendment,  Assignment and Assumption  Agreement dated as of September
          29,  1997 by and among The  Brooklyn  Union Gas  Company,  Long Island
          Lighting Company and KeySpan Energy  Corporation (filed as Exhibit 2.5
          to Schedule 13D by Long Island Lighting Company on October 24, 1997).

     2(c) Agreement and Plan of Merger dated as of June 26, 1997 by and among BL
          Holding  Corp.,  Long  Island  Lighting  Company,  Long  Island  Power
          Authority and LIPA Acquisition Corp. (filed as Annex D to Registration
          Statement on Form S-4 No. 333-30353 on June 30, 1997).

     2(d) Amended and Restated LILCO Stock Option Agreement between The Brooklyn
          Union Gas Company and Long Island  Lighting  Company  dated as of June
          26, 1997 (filed as Annex B to Registration  Statement on Form S-4, No.
          333-30353, on June 30, 1997).

     2(e) Amended and Restated  Brooklyn  Union Stock Option  Agreement  between
          Long Island Lighting  Company and The Brooklyn Union Gas Company dated
          as of June 26, 1997  (filed as Annex C to  Registration  Statement  on
          Form S-4, No. 333-30353, on June 30, 1997).

     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 (filed as an
          Exhibit to the  Company's  Form 10-K for the Year Ended  December  31,
          1996.)


                                      118

<PAGE>


     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).

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


                                      119


<PAGE>

                                                  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).


                                      120


<PAGE>

     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).

     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).


                                      121

<PAGE>

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

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

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

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

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

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


                                      122

<PAGE>

          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).

          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).


                                      123

<PAGE>

          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).


                                      124

<PAGE>

     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)Indenture  of  Trust  dated  as of  December  1,  1997 by and  between
          NYSERDA and The Chase Manhattan Bank, as Trustee, relating to the 1997
          EFRBs,  Series A (filed as an Exhibit to the  Company's  Form 10-Q for
          the period ended December 31, 1997).

          Participation  Agreement  dated as of  December 1, 1997 by and between
          NYSERDA and the Company relating to the 1997 EFRBs, Series A (filed as
          an Exhibit to the  Company's  Form 10-Q for the period ended  December
          31, 1997).

     10(z)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.


                                      125

<PAGE>

   10(aa) Executive Agreements and Management Contracts

     (1)  Executive  Employment  Agreement  dated as of January  30, 1984 by and
          between  William  J.  Catacosinos  and  the  Company,  as  amended  by
          amendments  dated March 20, 1987 (filed as an Exhibit to the Company's
          Form 10-K for the Year Ended  December  31,  1986),  December 22, 1989
          (filed as an  Exhibit  to the  Company's  Form 10-K for the Year Ended
          December 31,  1989),  and December 2, 1991 (filed as an Exhibit to the
          Company's  Form 10-K for the Year  Ended  December  31,  1991),  which
          amendment  was restated by an amendment  dated as of December 2, 1991,
          and  amendments  dated as of May 31, 1995 and August 4, 1995 (filed as
          Exhibits to the  Company's  Form 10-Q for the  Quarterly  Period Ended
          September 30, 1995);  an Executive  Employment  Agreement  dated as of
          August 4, 1995 (filed as an Exhibit to the Company's Form 10-Q for the
          Quarterly  Period ended  September 30, 1995; an amendment  dated as of
          December 29, 1996 (filed as an Exhibit to the Company's  Form 10-Q for
          the Quarterly Period Ended June 30, 1997).

     (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) Jane A.  Fernandez,  (3) James T.  Flynn,  (4)
          Joseph E. Fontana,  (5) Robert X. Kelleher,  (6) Howard A. Kosel dated
          as of April 1, 1997, (7) John D. Leonard, Jr., (8) Adam M. Madsen, (9)
          Kathleen A. Marion, (10) Brian R. McCaffrey, (11) Joseph W. McDonnell,
          (12)  Leonard  P.  Novello  dated as of April 1,  1995,  (13)  Anthony
          Nozzolillo, (14) Richard Reichler, (15) William G. Schiffmacher,  (16)
          Werner J.  Schweiger  dated as of  December 1, 1996,  (17)  Richard M.
          Siegel  dated as of December  1, 1996,  (18)  Robert B.  Steger,  (19)
          William E. Steiger, and (20) Edward J. Youngling.

     (3)  Executive  Employment Agreement by and between the Company and Michael
          E.  Bray  dated  as of March  1,  1997  (filed  as an  Exhibit  to the
          Company's  Form  10-  Q for  the  transition  period  from  1/1/97  to
          3/31/97.)


                                      126

<PAGE>

     (4)  Executive  Retention Agreement dated as of July 1, 1997 by and between
          the Company and Theodore A.  Babcock,  Vice  President  and  Treasurer
          (filed as an Exhibit to the  Company's  Form 10-Q for the period ended
          December  31,  1997),  which  agreement is  substantially  the same as
          Executive  Retention  Agreement  by and  between  the  Company and (1)
          Michael E. Bray, Senior Vice President;  (2) Charles A. Daverio,  Vice
          President;  (3) Jane A.  Fernandez,  Vice  President;  (4)  Joseph  E.
          Fontana, Vice President and Controller; (5) Robert X. Kelleher, Senior
          Vice  President;  (6) Howard A.  Kosel,  Vice  President;  (7) John D.
          Leonard,  Jr.,  Vice  President;  (8)  Adam  M.  Madsen,  Senior  Vice
          President;  (9)  Kathleen A.  Marion,  Vice  President;  (10) Brian R.
          McCaffrey,  Vice  President;  (11)  Joseph W.  McDonnell,  Senior Vice
          President;  (12) Leonard P. Novello, Senior Vice President and General
          Counsel;  (13) Anthony  Nozzolillo,  Senior Vice  President  and Chief
          Financial Officer; (14) Richard Reichler, Vice President; (15) William
          G. Schiffmacher, Senior Vice President; (16) Werner J. Schweiger, Vice
          President;  (17) Richard M.  Siegel,  Vice  President;  (18) Robert B.
          Steger,  Senior Vice  President;  (19)  William E.  Steiger,  Jr, Vice
          President, and (20) Edward J. Youngling,, Senior Vice President.

     (5)  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) Michael E. Bray dated as of March 1,
          1997, (2) Charles A. Daverio dated as of December 1, 1996, (3) Jane A.
          Fernandez  dated as of September 19, 1994, (4) James T. Flynn dated as
          of November  25, 1987,  (5) Joseph E. Fontana  dated as of October 20,
          1994, (6) George B. Jongeling dated as of April 1, 1998, (7) Robert X.
          Kelleher  dated as of November 25, 1987,  (8) Howard A. Kosel dated as
          of April 1, 1997,  (9) John D.  Leonard,  Jr. dated as of November 25,
          1987, (10) Adam M. Madsen dated as of November 25, 1987, (11) Kathleen
          A. Marion dated as of May 30, 1990,  (12) Brian R. McCaffrey  dated as
          of November 25, 1987,  (13) Joseph W. McDonnell  dated as of March 18,
          1988,  (14) Leonard P. Novello dated as of April 1, 1995, (15) Anthony
          Nozzolillo  dated as of July 29, 1992, (16) Richard  Reichler dated as
          of September 30, 1993,


                                      127

<PAGE>


          (17)  William G.  Schiffmacher  dated as of November  25,  1987,  (18)
          Werner J.  Schweiger  dated as of  December 1, 1996,  (19)  Richard M.
          Siegel dated as of December 1, 1996, (20) Robert B. Steger dated as of
          February 20, 1990,  (21) William E. Steiger,  Jr. dated as of March 1,
          1989, and (22) Edward J. Youngling dated as of November 4, 1988.

     (6)  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)  Katherine D. Ortega dated as of
          April 20, 1993,  (6) Basil A. Paterson  dated as of November 19, 1987,
          (7) Richard L. Schmalensee dated as of February 8, 1992, (8) George J.
          Sideris  dated as of November 30, 1987,  and (9) John H. Talmage dated
          as of November 19, 1987.

     (7)  Indemnification  Agreement by and between the Company and Eben W. Pyne
          dated as of April 20, 1993, (filed as an Exhibit to the Company's Form
          10-K for the Year Ended December 31, 1993.)

     (8)  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).

     (9)  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).

     (10) 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).


                                      128

<PAGE>

*(11)     Consulting  Agreement  dated as of August 9, 1997 by and  between  the
          Company and Eben W. Pyne.

*18       Letter re change in accounting principles.   

*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 UT for the twelve-month
          period ended March 31, 1998.

                  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

            None.

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


                                      129

<PAGE>

<PAGE>

                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

                             (Thousands of Dollars)

<TABLE>
<CAPTION>
--------------------------------------- -------------- ------------------------------- --------------- ---------------
               Column A                   Column B                Column C             Column D        Column E
--------------------------------------- -------------- ------------------------------- --------------- ---------------
                                                                 Additions
                                                       ---------------- --------------
                                         Balance at    Charged to       Charged to                     Balance at
             Description                beginning of   costs and        other          Deductions-     end of period
                                           period      expenses         accounts-      describe
                                                                        describe
--------------------------------------- -------------- ---------------- -------------- --------------- ---------------
----------------------------------------------------------------------------------------------------------------------
<S>                                         <C>          <C>              <C>           <C>                 <C>    
Year ended March 31, 1998
  Deducted from asset accounts:
  Allowance for doubtful accounts           $23,675      $23,239          --            $23,431(1)          $23,483
                                                                          
Three Months Ended March 31, 1997                                         
  Deducted from asset accounts:                                           
  Allowance for doubtful accounts           $25,000      $ 4,821          --             $6,146(1)          $23,675
                                                                          
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

</TABLE>
                                                                          
(1) Uncollectible accounts written off, net of recoveries.                


                                       130

<PAGE>

                                   SIGNATURES

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

Date

May 28, 1998
                                        Signature and Title


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

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

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


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


                           --------------------------------------------
                                        GEORGE BUGLIARELLO*
                                   George Bugliarello, Director

                           --------------------------------------------
                                        RENSO L. CAPORALI*
                                    Renso L. Caporali, Director

                           --------------------------------------------
                                         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)



                                       131

<PAGE>



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

                                            LONG ISLAND LIGHTING COMPANY

Date:  May 28, 1998                         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,
are being filed with the Securities and Exchange Commission.


                                       132