SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549


                                   FORM 10-K/A
                                AMENDMENT NO. 2

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

                       SECURITIES EXCHANGE ACT OF 1934

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996


                         COMMISSION FILE NUMBER 1-3571

                         LONG ISLAND LIGHTING COMPANY

              INCORPORATED PURSUANT TO THE LAWS OF NEW YORK STATE


     INTERNAL REVENUE SERVICE - EMPLOYER IDENTIFICATION NUMBER 11-1019782

            175 EAST OLD COUNTRY ROAD, HICKSVILLE, NEW YORK  11801

                                 516-755-6650

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

                      TITLE OF EACH CLASS SO REGISTERED:

Common Stock ($5 par)

Preferred Stock ($100 par, cumulative):
Series B, 5.00%            Series E, 4.35%       Series I, 5 3/4%, Convertible
Series D, 4.25%            Series CC, 7.66%


Preferred Stock ($25 par, cumulative):
Series AA, 7.95%           Series GG, $1.67      Series QQ, 7.05%
                           Series NN, $1.95


General and Refunding Bonds:
8 3/4% Series Due 1997  8 5/8% Series Due 2004   9 3/4% Series Due 2021
7 5/8% Series Due 1998   8.50% Series Due 2006   9 5/8% Series Due 2024
 7.85% Series Due 1999   7.90% Series Due 2008


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

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

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

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

                                 Yes |X| No | |

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

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

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

<PAGE>




This Form 10-K/A  amends Part II, Items 7 and 8 of Form 10-K for the Fiscal Year
ended December 31, 1996.

                                    PART II

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

RESULTS OF OPERATIONS

EARNINGS

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

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

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

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

The  Company's  1995 earnings per common share were lower than 1994 earnings per
common share as a result of the New York State Public Service Commission's (PSC)
electric rate order, effective December 1, 1994, that lowered the allowed return
on common  equity  from 11.6% to 11.0% and  modified  certain  performance-based
incentives.  Partially  offsetting  the effects on earnings of the electric rate
order was higher gas business earnings in 1995 when compared to 1994.


                                       1

<PAGE>

REVENUES

ELECTRIC REVENUES

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

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

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

GAS REVENUES

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

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

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

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

The  recovery  of gas fuel  expenses  in 1996 when  compared  to 1995  increased
approximately $31 million as a result of higher average gas

 

                                        2


<PAGE>



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

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

OPERATING EXPENSES

FUEL AND PURCHASED POWER

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

                                                        (In millions of dollars)
--------------------------------------------------------------------------------
                                           1996            1995          1994
--------------------------------------------------------------------------------
Fuel for Electric Operations
  Oil                                     $ 158          $  98          $ 145
  Gas                                       138            149            101

  Nuclear                                    15             14             15

  Purchased power                           329            310            308
--------------------------------------------------------------------------------
Total                                       640            571            569
================================================================================
Gas fuel                                    323            264            279
--------------------------------------------------------------------------------
Total                                    $  963          $ 835          $ 848
================================================================================


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

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

During 1996, the Company  completed the first of two planned  conversions of oil
fired steam generating units at its Port Jefferson Power Station to


                                       3

<PAGE>



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

As a result of a sharp  increase  in the cost of  natural  gas  during the year,
generation  with oil became more  economical than generation with gas. The total
barrels of oil consumed for electric  operations were 7.1 million,  5.2 million,
and 7.5 million for the years 1996, 1995 and 1994, respectively.

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

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

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

OPERATIONS AND MAINTENANCE EXPENSES

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

RATE MODERATION COMPONENT

The Rate  Moderation  Component  (RMC)  represents  the  difference  between the
Company's revenue  requirements under  conventional  ratemaking and the revenues
provided by its electric  rate  structure.  The RMC is adjusted  monthly for the
operation of the Company's Fuel Moderation Component (FMC)


                                       4

<PAGE>



mechanism and the  difference  between the Company's  share of actual  operating
costs at Nine Mile  Point  Nuclear  Power  Station,  Unit 2 (NMP2)  and  amounts
provided for in electric rates.

In 1996, the Company recorded a non-cash credit to income of  approximately  $50
million, representing the amount by which revenue requirements exceeded revenues
provided for under the current  electric rate  structure.  Partially  offsetting
this accretion were the effects of the FMC mechanism and the differences between
actual  and  adjudicated  operating  costs for NMP2,  as  discussed  above.  The
adjustments  to the  accretion  of the RMC  totaled  $26  million,  of which $24
million was derived from the operation of the FMC mechanism.

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

   
Based  on  the  Company's  current  long-range  projections  for  energy  sales,
operations  and  maintenance  costs,  property  taxes,  construction  and  other
expenditures,  the RMC balance  will be fully  amortized by year-end  2001.  The
assumptions used in the forecast are as follows: (i) the Company's base electric
rates remain at current levels through the year 2001; (ii) the Company  receives
PSC permission to credit the Phase I Shoreham  property tax litigation  proceeds
that the Company  received in January 1996 to the RMC balance in 1997,  at which
time the proceeds plus  interest are expected to be $83 million;  and (iii) $360
million of the total  judgment  awarded the Company in Phase II of the  Shoreham
property tax case is received by the Company  during the 1999 to 2001 time frame
and will be applied to reduce the RMC balance.  Based upon the assumptions  used
in this  forecast,  RMC  non-cash  charges to income will be  approximately  $52
million in 1997, $89 million in 1998,  $143 million in 1999, $57 million in 2000
and $57 million in 2001.  These  estimates are based on the multi-year rate plan
(Plan)  submitted  to the PSC in September  1996.  

If the assumptions  outlined  immediately  above are not adopted by the PSC, the
Company  proposed as an  alternative in the September 1996 filing that, in order
to insure  the timely and  certain  recovery  of any  remaining  RMC  balance at
November 30, 1999,  that the Company recover any such balance through rates over
a two year period using its Fuel Adjustment Clause. By using the Fuel Adjustment
Clause,  which it has  used in the  past to  recover  other  regulatory  assets,
customer  bills  would be  automatically  adjusted  in order  to  amortize  on a
straight-line-basis  any  remaining  RMC balance  over a two year period  ending
November 30, 2001.

Based upon the above,  and the fact that  actions of the PSC continue to support
the full recovery of the Shoreham related  regulatory assets, as provided in the
Rate Moderation  Agreement (RMA), the Company believes that future revenues will
be provided  specifically  for the  recovery of the RMC  balance.  For a further
discussion of the plan, see Rate Matters, under the heading "Electric."
    

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

OTHER REGULATORY AMORTIZATION

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

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

The electric revenue reconciliation mechanism, as established under the


                                       5

<PAGE>



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

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

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

OPERATING TAXES

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

FEDERAL INCOME TAX

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

OTHER INCOME AND DEDUCTIONS, NET

Other  income and  deductions,  totaled $19  million  for 1996,  compared to $34
million and $35 million for 1995 and 1994,  respectively.  The  decrease in 1996
when  compared  to  1995  is  primarily   attributable  to  the  recognition  of
nonrecurring  expenditures  associated  with one of the  Company's  wholly-owned
subsidiaries,  a decrease in non-cash  carrying  charge income  associated  with
regulatory assets not currently in rate base and the recognition in 1995 of

                                       6
<PAGE>



certain litigation  proceeds related to the construction of the Shoreham Nuclear
Power  Station.  The change from 1995 when  compared to 1994, in addition to the
effects  of the  litigation  proceeds,  resulted  from lower  non-cash  carrying
charges  and lower  incentive  income as a result of the PSC rate  order for the
rate year ended November 30, 1995,  which eliminated  certain  performance-based
incentives.

INTEREST EXPENSE

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

                                       7
<PAGE>



LIQUIDITY

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

At December  31,  1996,  the  Company's  cash and cash  equivalents  amounted to
approximately  $280  million,  compared to $351 million at December 31, 1995. In
addition,  the Company  has  available  for its use a  revolving  line of credit
through October 1, 1997,  provided by its 1989 Revolving  Credit Agreement (1989
RCA). In July 1996, at the Company's request,  the amount committed by the banks
participating in the facility was reduced from $300 million to $250 million. The
Company  believes this action is  appropriate  given the levels of cash on hand,
projected  future cash generated  from  operations and modest debt and preferred
stock  maturities  through 1998.  This line of credit is secured by a first lien
upon the Company's accounts  receivable and fuel oil inventories.  For a further
discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements.

In January  1996,  the Company  received  approximately  $81 million,  including
interest, from Suffolk County pursuant to a judgment in the Company's favor that
found that the  Shoreham  property  was  overvalued  for  property  tax purposes
between 1976 and 1983 (excluding  1979 which had previously  been settled).  The
Company has petitioned the PSC to allow the Company to reduce the RMC balance by
the amount received,  net of litigation  costs incurred by the Company.  The PSC
has not yet  acted  on the  Company's  petition  and,  therefore,  such  amounts
continue to be  deferred  on the  Company's  balance  sheet as other  regulatory
liabilities.

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

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

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

                                       8
<PAGE>



made  available  to it by the New York State  Energy  Research  and  Development
Authority  (NYSERDA).  With respect to the repayment of $101 million of maturing
debt in 1998 and the  repayment of $454 million of maturing debt and $22 million
of mandatory  redemption  requirements  of preferred  stock in 1999, the Company
intends to use cash generated from operations to the maximum extent practicable.

In 1990 and 1992,  the Company  received  Revenue  Agents'  Reports  disallowing
certain  deductions and credits claimed by the Company on its federal income tax
returns for the years 1981 through 1989.  The Revenue  Agents'  Reports  reflect
proposed adjustments to the Company's federal income tax returns for this period
which, if sustained,  would give rise to tax deficiencies totaling approximately
$227  million.  The  Company  believes  that any such  deficiencies  as  finally
determined would be significantly  less than the amounts proposed in the Revenue
Agents'  Reports.  The Company has  protested  some of the proposed  adjustments
which are presently under review by the Regional  Appeals Office of the Internal
Revenue  Service.  The  Company  believes  that  cash  balances  at the  time of
settlement  will be sufficient to satisfy any settlement  reached.  However,  if
necessary,  the Company will avail itself of interim  financing via the 1989 RCA
to meet this obligation. The Company currently believes that a settlement of the
1981  through 1989 years  should be reached  with the  Regional  Appeals  Office
sometime in 1997.

CAPITALIZATION

The Company's capitalization, including current maturities of long-term debt and
current  redemption  requirements  of preferred  stock, at December 31, 1996 and
1995, was $7.9 billion and $8.3 billion,  respectively. At December 31, 1996 and
1995, the Company's capitalization ratios were as follows:


                                           1996                   1995
--------------------------------------------------------------------------------
   Long-term debt                          59.3%                  61.8%
   Preferred stock                          8.9                    8.6
   Common shareowners' equity              31.8                   29.6
--------------------------------------------------------------------------------
                                          100.0%                 100.0%
================================================================================

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

INVESTMENT RATING

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

                                       9
<PAGE>



watching  the  electric  utility  industry  closely and have  expressed  concern
regarding the ability of high cost  utilities,  such as the Company,  to recover
all of their fixed costs in a competitive, deregulated marketplace.

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

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

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

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

                           S&P        Moody's       Fitch      D&P
--------------------------------------------------------------------------------
G&R Bonds                  BBB-       Ba1           BBB-       BBB

Debentures                 BB+        Ba3           BB+        BB+

Preferred Stock            BB+        ba3           BB-*       BB
--------------------------------------------------------------------------------
MINIMUM INVESTMENT
   GRADE                   BBB-       Baa3          BBB-       BBB-
================================================================================
Bold face indicates securities that meet or exceed minimum investment grade.

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

                                       10

<PAGE>



CAPITAL REQUIREMENTS AND CAPITAL PROVIDED

Capital requirements and capital provided for 1996 and 1995 were as follows:

                                                   (In millions of dollars)
--------------------------------------------------------------------------------
                                                     1996            1995
--------------------------------------------------------------------------------
CAPITAL REQUIREMENTS
Construction*
   Electric                                         $ 142            $ 144
   Gas                                                 71               79
   Common                                              27              21
--------------------------------------------------------------------------------
Total Construction                                    240              244
--------------------------------------------------------------------------------
Refundings and Dividends
   Long-term debt                                     415              100
   Preferred stock                                      5                5
   Common stock dividends                             214              211
   Preferred stock dividends                           52               53
--------------------------------------------------------------------------------
Total Refundings and Dividends                        686              369
--------------------------------------------------------------------------------
Shoreham post-settlement costs                         52               71
--------------------------------------------------------------------------------
TOTAL CAPITAL REQUIREMENTS                          $ 978            $ 684
================================================================================

CAPITAL PROVIDED
Cash generated from operations                      $ 892            $ 772
Long-term debt issued                                   -               49
Common stock issued                                    19               20
Other investing activities                             (4)               9
Increase(decrease) in cash                             71             (166)
--------------------------------------------------------------------------------
Total Capital Provided                              $ 978            $ 684
================================================================================
* Excludes  non-cash  allowance  for other funds used during  construction.  For
further information, see the Statement of Cash Flows.

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

Based upon the  projections  of peak  demand for  electric  power,  the  Company
believes it will need to acquire additional  generating or demand-side resources
starting  in 1998  in  order  to  maintain  satisfactory  electric  supply.  The
Company's Integrated Electric Resource Plan (IERP),  recommends a combination of
a peak load reduction demand-side  management program and a capacity purchase as
the most economical method of meeting this need. The

                                       11
<PAGE>



IERP projects that new electric generating capacity will need to be installed on
Long Island to meet peak demand in the summer of 2001.  It is  anticipated  that
such new capacity would be acquired through a competitive bidding process.

MERGER AGREEMENT WITH THE BROOKLYN UNION GAS COMPANY

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

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

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

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

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

                                       12

<PAGE>

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

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

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

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

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

RATE MATTERS

ELECTRIC

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

                                       13

<PAGE>



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

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

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

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

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

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

1995 ELECTRIC RATE ORDER

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

                                       14

<PAGE>



electric rates, reduced the Company's allowed return on common equity from 11.6%
to 11.0% and modified or eliminated  certain  performance-based  incentives,  as
discussed below.

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

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

The expense attrition and  reconciliation  component permits the Company to make
adjustments  for certain  expenses  recognizing  that these cost  increases  are
unavoidable  due to  inflation  and changes  outside the control of the Company.
Pursuant to the 1995 Order,  the Company is permitted to reconcile  expenses for
property  taxes only,  whereas  under the original  LRPP the Company was able to
reconcile  expenses for wage rates,  property  taxes,  interest costs and demand
side management (DSM) costs.

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

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

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

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


                                       15
<PAGE>



The deferred balances resulting from the net margin and expense reconciliations,
and earned performance-based incentives are netted at the end of each rate year,
as established  under the LRPP and continued under the 1995 Order. The first $15
million of the total  deferral is recovered  from or credited to  ratepayers  by
increasing  or  decreasing  the RMC  balance.  Deferrals  in  excess  of the $15
million,  upon  approval  of the PSC,  are  refunded  to or  recovered  from the
customers through the FCA mechanism over a 12-month period.

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

Another  mechanism of the LRPP  provides  that earnings in excess of the allowed
return on common equity,  excluding the impacts of the various  incentive and/or
penalty programs,  are used to reduce the RMC. For the rate years ended November
30,  1996  and  1995,   the  Company  earned  $9.1  million  and  $6.2  million,
respectively,  in excess of its allowed  return on common  equity.  These excess
earnings  were applied as  reductions  to the RMC. In 1994,  the Company did not
earn in excess of its allowed return on common equity.

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

GAS

In December 1993, the PSC approved a three year gas rate settlement  between the
Company and the Staff of the PSC. The gas rate  settlement  provided  annual gas
rate increases of 4.7%, 3.8% and 3.2% for each of the three rate years beginning
December 1, 1993,  1994, and 1995,  respectively.  In the  determination  of the
revenue  requirements for the gas rate  settlement,  an allowed return on common
equity of 10.1% was used.

The gas rate  settlement also provided that earnings in excess of a 10.6% return
on common equity be shared equally  between the Company's firm gas customers and
its shareowners.  For the rate years ended November 30, 1996, 1995 and 1994, the
firm gas  customers'  portion of gas earnings in excess of the allowed return on
common  equity  totaled  approximately  $10 million,  $1 million and $7 million,
respectively. In 1996, the Company was granted

                                       16
<PAGE>



permission by the PSC to apply the customers' portion of the gas excess earnings
and associated carrying charges for the 1995 and 1994 rate years to the recovery
of deferred costs  associated with  postretirement  benefits other than pensions
and costs incurred for  investigation  and remediation of manufactured gas plant
(MGP) sites.  The Company has requested  that the same  treatment be granted for
the  disposition  of the  customers'  portion  of the 1996 rate year gas  excess
earnings.

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

COMPETITIVE ENVIRONMENT

The electric industry  continues to undergo  fundamental  changes as regulators,
elected officials and customers seek lower energy prices.  These changes,  which
may have a  significant  impact  on future  financial  performance  of  electric
utilities,  are being  driven  by a number of  factors  including  a  regulatory
environment in which traditional  cost-based  regulation is seen as a barrier to
lower energy prices.  In 1996,  both the PSC and the Federal  Energy  Regulatory
Commission  (FERC)  continued  their  separate,  but  in  some  cases  parallel,
initiatives  with respect to developing a framework  for a competitive  electric
marketplace.

THE ELECTRIC INDUSTRY - STATE REGULATORY ISSUES

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

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

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

The Order  contemplates  that  implementation of competition will proceed on two
tracks.   The  Order   requires  that  each  major   electric   utility  file  a
rate/restructuring plan which is consistent with the PSC's policy and

                                       17
<PAGE>



vision for increased competition. Those plans were submitted by October 1, 1996,
in  compliance  with the Order.  However,  the  Company was  exempted  from this
requirement due to the PSC's separate  investigation  of the Company's rates and
LIPA's  examination  of  the  Company's   structure.   Since  October  1,  1996,
proceedings  have  commenced  for  the  five  electric   utilities  which  filed
restructuring  plans in accordance with track one and the Company has intervened
in each of these proceedings.

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

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

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

                                       18
<PAGE>



operations  and  financial  conditions  of New  York's  investor-owned  electric
utilities, including the Company.

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

THE ELECTRIC INDUSTRY - FEDERAL REGULATORY ISSUES

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

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

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

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

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

In September 1996, the FERC ordered Rate Hearings on 28 utility

                                       19
<PAGE>



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

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

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

   
It is not possible to predict the  ultimate  outcome of these  proceedings,  the
timing thereof,  or the amount, if any, of stranded costs that the Company would
recover in a  competitive  environment.  The  outcome  of the state and  federal
regulatory  proceedings  could adversely  affect the Company's  ability to apply
Statement of Financial  Accounting  Standards (SFAS) No. 71, "Accounting for the
Effects  of Certain  Types of  Regulation,"  which,  pursuant  to SFAS No.  101,
"Accounting  for  Discontinuation  of  Application  of SFAS No.  71," could then
require a  significant  write-down  of all or a  portion  of the  Company's  net
regulatory  assets.  If the  Company  were  unable  to  continue  to  apply  the
provisions  of SFAS No. 71 at December  31,  1996,  the Company  estimates  that
approximately $4.6 billion would have been written off at such time.
    

                                       20
<PAGE>



THE COMPANY'S SERVICE TERRITORY

The Company's geographic location and the limited electrical interconnections to
Long  Island  serve to  limit  the  accessibility  of its  transmission  grid to
potential  competitors  from  off the  system.  However,  the  changing  utility
regulatory  environment  has affected  the Company by  requiring  the Company to
co-exist with state and federally  mandated  competitors.  These competitors are
non-utility generators (NUGS), NYPA and Municipal Distribution Agencies (MDAs).

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

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

The increase in lost net revenues  resulted  principally  from the completion of
seven facilities that became  commercially  operational during 1996 and the full
year  operation of the IPP located at the State  University of New York at Stony
Brook, NY. The Company  estimates that in 1997, sales losses to NUGs will be 429
GWh, or approximately 1.8% of projected net revenues.

The Company believes that load losses due to NUGs have  stabilized.  This belief
is based on the fact that the  Company's  customer load  characteristics,  which
lack a significant industrial base and related large thermal load, will mitigate
load loss and thereby make cogeneration economically unattractive.

Additionally,  as mentioned  above,  the Company is required to purchase all the
power offered by QFs which in 1996  approximated 218 megawatts (MW) and in early
1995  approximated  205 MW. The  increase was the result of the SUNY Stony Brook
facility  going on line in mid 1995.  The Company  estimates that purchases from
QFs  required  by federal  and state law cost the  Company  $63  million and $53
million  in 1996 and 1995,  respectively,  more than it would  have cost had the
Company generated this power.

QFs have the  choice  of  pricing  sales to the  Company  at  either  the  PSC's
published  estimates of the  Company's  long-range  avoided  costs (LRAC) or the
Company's  tariff rates,  which are modified from time to time,  reflecting  the
Company's actual avoided costs.  Additionally,  until repealed in 1992, New York
State law set a minimum price of six cents per  kilowatt-hour  (kWh) for utility
purchases  of power  from  certain  categories  of QFs,  considerably  above the
Company's avoided cost. The six cent minimum continues to apply

                                       21
<PAGE>



to contracts entered into before June 1992. The Company believes that the repeal
of the six cent minimum, coupled with recent PSC updates which resulted in lower
LRAC estimates,  has significantly reduced the economic benefits of constructing
new QFs within its service territory.

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

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

In  addition,  several  towns and  villages  on Long  Island  are  investigating
municipalization, in which customers form a government-sponsored electric supply
company.  This is one form of competition that is likely to increase as a result
of the  National  Energy  Policy Act of 1992  (NEPA).  NEPA  sought to  increase
economic  efficiency  in the  creation  and  distribution  of power by  relaxing
restrictions  on the entry of new  competitors  to the wholesale  electric power
market. NEPA does so by creating exempt wholesale generators that can sell power
in  wholesale  markets  without  the  regulatory  constraint  placed on  utility
generators  such as on the Company.  NEPA also expanded the FERC's  authority to
grant access to utility  transmission  systems to all parties who seek wholesale
wheeling  for  wholesale  competition.  While it should be noted that the FERC's
position favoring stranded cost recovery from retail turned wholesale  customers
will reduce utility risk from  municipalization,  significant  issues associated
with the removal of  restrictions on wholesale  transmission  system access have
yet to be resolved.

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

In 1995,  Suffolk  County issued a request for proposal from suppliers for up to
300 MW of  power  which  the  County  would  then  sell to its  residential  and
commercial  customers.  The County has  awarded the bid to two  off-Long  Island
suppliers and has requested the Company to deliver the power.  After the Company
challenged Suffolk County's  eligibility for such service, the County petitioned
the FERC to order the Company to provide the requested transmission service.

In December 1996, the FERC ordered the Company to provide transmission  services
to Suffolk County to the extent necessary to accommodate proposed

                                       22
<PAGE>



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

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

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

ENVIRONMENTAL MATTERS

The Company is subject to federal,  state and local laws and regulations dealing
with air and  water  quality  and  other  environmental  matters.  Environmental
matters  may  expose the  Company to  potential  liabilities  which,  in certain
instances,  may be imposed without regard to fault or for historical  activities
which were lawful at the time they occurred.  The Company  continually  monitors
its  activities  in order to  determine  the  impact  of its  activities  on the
environment and to ensure compliance with various  environmental laws. Except as
set  forth  below,  no  material  proceedings  have  been  commenced  or, to the
knowledge of the Company,  are contemplated  against the Company with respect to
any matter relating to the protection of the environment.

The New York State Department of Environmental  Conservation  (DEC) has required
the  Company  and other New York  State  utilities  to  investigate  and,  where
necessary, remediate their former manufactured gas plant (MGP) sites. Currently,
the  Company  is the owner of six  pieces of  property  on which the  Company or
certain of its predecessor  companies are believed to have produced manufactured
gas. Operations at these facilities in the late 1800's and early 1900's may have
resulted in the disposal of certain waste  products on these sites.  Research is
underway to determine the existence

                                       23
<PAGE>



and nature of operations and their relationship, if any, to the Company or
its predecessor companies.

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

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

The Company  has been  notified by the United  States  Environmental  Protection
Agency (EPA) that it is one of many PRPs that may be liable for the  remediation
of three licensed treatment, storage and disposal sites to which the Company may
have shipped waste products and which have subsequently  become  environmentally
contaminated.

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

The Company has also been named a PRP for disposal sites in Kansas City, Kansas,
and Kansas City, Missouri.  The two sites were used by a company named PCB, Inc.
from 1982 until 1987 for the  storage,  processing,  and  treatment  of electric
equipment,  dielectric oils and materials containing PCBs. According to the EPA,
the buildings and certain soil areas outside the buildings are contaminated with
PCBs.

                                       24
<PAGE>



In 1994,  the EPA requested  certain of the large PRPs,  which  include  several
other utilities, to form a group, sign an ACO, and conduct a remediation program
for the sites under the Toxic Substances Control Act, or in the alternative,  to
perform a Superfund cleanup for the sites. The EPA has provided the Company with
documents  indicating  that the Company was  responsible for less than 1% of the
materials  that were shipped to the Missouri site. The EPA has not yet completed
compiling the documents for the Kansas site.  The Company  intends to join a PRP
Group which includes other  utilities,  which has been organized for the purpose
of developing and implementing  acceptable  remediation  programs for the sites.
The Company is currently  unable to determine its share of the cost to remediate
these sites.

In  addition,  the Company  was  notified  that it is a PRP at a Superfund  site
located  in  Farmingdale,   New  York.   Portions  of  the  site  are  allegedly
contaminated  with PCBs,  solvents and metals.  The Company was also notified by
other PRPs that it should be responsible for remediation  expenses in the amount
of approximately $100,000 associated with removing PCB-contaminated soils from a
portion of the site which formerly contained electric transformers.  The Company
is unable to determine its share of costs of remediation at this site.

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

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

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

                                       25
<PAGE>



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

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

CONSERVATION SERVICES

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

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

                                       26
<PAGE>



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

SELECTED FINANCIAL DATA

Additional information respecting revenues, expenses, electric and gas operating
income and operations data and balance sheet information for the last five years
is  provided  in  Tables  1  through  11 of Item  6:  Selected  Financial  Data.
Information  with regard to the Company's  business  segments for the last three
years is provided in Note 12 of Notes to Financial Statements.


                                       27
<PAGE>


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


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

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

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

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

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

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

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

SEE NOTES TO FINANCIAL STATEMENTS.

                                       28
<PAGE>

<TABLE>
<CAPTION>

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

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

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

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

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

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

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

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

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

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

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

SEE NOTES TO FINANCIAL STATEMENTS.

                                       29
<PAGE>

<TABLE>
<CAPTION>

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

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

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

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

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

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

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

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

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

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

                                       30
<PAGE>

<TABLE>
<CAPTION>

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

INVESTING ACTIVITIES

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

FINANCING ACTIVITIES

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


Interest paid, before reduction for the allowance
   for borrowed funds used during constuction          $     404,663   $   427,988   $   446,340
Federal income tax - paid                              $      45,050   $    14,200   $    10,780
-------------------------------------------------------------------------------------------------
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
                                       31
<PAGE>

<TABLE>
<CAPTION>

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

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

SEE NOTES TO FINANCIAL STATEMENTS.


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

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

PREFERRED STOCK - REDEMPTION REQUIRED
Par value $100 per share
      7.40% Series L                                             161,000           171,500            16,100           17,150
      8.50% Series R                                                   -            37,500                 -            3,750
      7.66% Series CC                                            570,000           570,000            57,000           57,000
Less - Sinking fund requirement                                                                        1,050            4,800
------------------------------------------------------------------------------------------------------------------------------
                                                                                                      72,050           73,100
------------------------------------------------------------------------------------------------------------------------------
Par value $25 per share
      7.95% Series AA                                         14,520,000        14,520,000           363,000          363,000
      $1.67 Series GG                                            880,000           880,000            22,000           22,000
      $1.95 Series NN                                          1,554,000         1,554,000            38,850           38,850
      7.05% Series QQ                                          3,464,000         3,464,000            86,600           86,600
      6.875% Series UU                                         2,240,000         2,240,000            56,000           56,000
------------------------------------------------------------------------------------------------------------------------------
                                                                                                     566,450          566,450
------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required                                                          638,500          639,550
------------------------------------------------------------------------------------------------------------------------------

PREFERRED STOCK - NO REDEMPTION REQUIRED
Par value $100 per share
      5.00% Series B                                             100,000           100,000            10,000           10,000
      4.25% Series D                                              70,000            70,000             7,000            7,000
      4.35% Series E                                             200,000           200,000            20,000           20,000
      4.35% Series F                                              50,000            50,000             5,000            5,000
      5 1/8% Series H                                            200,000           200,000            20,000           20,000
      5 3/4% Series I -  Convertible                              16,637            19,336             1,664            1,934
------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required                                                        63,664           63,934
------------------------------------------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK                                                                             $  702,164    $     703,484    
------------------------------------------------------------------------------------------------------------------------------
</TABLE>
                                       32
<PAGE>

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

<S>                                      <C>                           <C>             <C>       <C>              <C>
GENERAL AND REFUNDING BONDS
                                               May 1, 1996             8 3/4%                              -          415,000
                                         February 15, 1997             8 3/4%                        250,000          250,000
                                            April 15, 1998             7 5/8%                        100,000          100,000
                                              May 15, 1999             7.85%                          56,000           56,000
                                            April 15, 2004             8 5/8%                        185,000          185,000
                                              May 15, 2006             8.50%                          75,000           75,000
                                             July 15, 2008             7.90%                          80,000           80,000
                                               May 1, 2021             9 3/4%                        415,000          415,000
                                              July 1, 2024             9 5/8%                        375,000          375,000
------------------------------------------------------------------------------------------------------------------------------
Total General and Refunding Bonds                                                                  1,536,000        1,951,000
------------------------------------------------------------------------------------------------------------------------------
DEBENTURES
                                             July 15, 1999             7.30%                         397,000          397,000
                                          January 15, 2000             7.30%                          36,000           36,000
                                             July 15, 2001             6.25%                         145,000          145,000
                                            March 15, 2003             7.05%                         150,000          150,000
                                             March 1, 2004             7.00%                          59,000           59,000
                                              June 1, 2005             7.125%                        200,000          200,000
                                             March 1, 2007             7.50%                         142,000          142,000
                                             July 15, 2019             8.90%                         420,000          420,000
                                          November 1, 2022             9.00%                         451,000          451,000
                                            March 15, 2023             8.20%                         270,000          270,000
------------------------------------------------------------------------------------------------------------------------------
Total Debentures                                                                                   2,270,000        2,270,000
------------------------------------------------------------------------------------------------------------------------------
AUTHORITY FINANCING NOTES
Industrial Development Revenue Bonds
                                          December 1, 2006             7.50%           1976 A,B        2,000            2,000
Pollution Control Revenue Bonds
                                          December 1, 2006             7.50%           1976 A         28,375           28,375
                                          December 1, 2009             7.80%           1979 B         19,100           19,100
                                           October 1, 2012             8 1/4%          1982           17,200           17,200
                                             March 1, 2016             3.25%           1985 A,B      150,000          150,000
Electric Facilities Revenue Bonds
                                         September 1, 2019             7.15%           1989 A,B      100,000          100,000
                                              June 1, 2020             7.15%           1990 A        100,000          100,000
                                          December 1, 2020             7.15%           1991 A        100,000          100,000
                                          February 1, 2022             7.15%           1992 A,B      100,000          100,000
                                            August 1, 2022             6.90%           1992 C,D      100,000          100,000
                                          November 1, 2023             4.05%           1993 A         50,000           50,000
                                          November 1, 2023             4.00%           1993 B         50,000           50,000
                                           October 1, 2024             4.00%           1994 A         50,000           50,000
                                            August 1, 2025             4.00%           1995 A         50,000           50,000
------------------------------------------------------------------------------------------------------------------------------
Total Authority Financing Notes                                                                      916,675          916,675
------------------------------------------------------------------------------------------------------------------------------
Unamortized Discount on Debt                                                                         (14,903)         (16,075)
------------------------------------------------------------------------------------------------------------------------------
Total                                                                                              4,707,772        5,121,600
Less Current Maturities                                                                              251,000          415,000
------------------------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT                                                                               4,456,772        4,706,600
------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION                                                                             $ 7,682,305      $ 7,863,037       
==============================================================================================================================
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS.

                                       33

<PAGE>

Note 1. Summary of Significant Accounting Policies

NATURE OF OPERATIONS

Long  Island  Lighting  Company  (Company)  was  incorporated  in 1910 under the
Transportation  Corporations Law of the State of New York and supplies  electric
and gas service in Nassau and Suffolk Counties and to the Rockaway  Peninsula in
Queens County,  all on Long Island,  New York. The Company's  service  territory
covers an area of  approximately  1,230  square  miles.  The  population  of the
service area,  according to the Company's  1996  estimate,  is about 2.7 million
persons,  including  approximately  98,000  persons who reside in Queens  County
within the City of New York.

The Company  serves  approximately  1.03  million  electric  customers  of which
approximately 921,000 are residential. The Company receives approximately 49% of
its electric revenues from residential customers, 48% from commercial/industrial
customers and the balance from sales to other utilities and public  authorities.
The Company also serves  approximately  460,000 gas customers,  412,000 of which
are residential, accounting for 61% of the gas revenues, with the balance of the
gas  revenues  made up by the  commercial/industrial  customers  and  off-system
sales.

The Company's geographic location and the limited electrical interconnections to
Long  Island  serve to  limit  the  accessibility  of the  transmission  grid to
potential  competitors  from off the system.  In addition,  the Company does not
expect any new major  independent  power producers  (IPPs) or cogenerators to be
built on Long Island in the foreseeable  future.  One of the reasons  supporting
this  conclusion  is based on the  Company's  belief  that the  composition  and
distribution  of the Company's  remaining  commercial and  industrial  customers
would make it difficult  for large  electric  projects to operate  economically.
Furthermore,  under  federal  law,  the  Company is  required to buy energy from
qualified  producers at the Company's avoided cost.  Current  long-range avoided
cost estimates for the Company have significantly reduced the economic advantage
to entrepreneurs seeking to compete with the Company and with existing IPPs. For
a further discussion of the competitive issues facing the Company, see Note 11.

REGULATION

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


                                       34
<PAGE>



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.

Regulatory assets represent probable future revenues  associated with previously
incurred  costs that are expected to be  recovered  from  customers.  Regulatory
liabilities  represent  probable future  reductions in revenues  associated with
amounts  that are expected to be refunded to  customers  through the  ratemaking
process.   Regulatory   assets  net  of  regulatory   liabilities   amounted  to
approximately  $6.7  billion  and $6.8  billion at  December  31, 1996 and 1995,
respectively.

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

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

Notwithstanding  the above, rate regulation is undergoing  significant change as
regulators  and  customers  seek lower prices for  electric and gas service.  As
discussed more fully in Note 11, the PSC has made a decision in the  Competitive
Opportunities  Proceedings  to transition  the electric  industry to a wholesale
power market in early 1997 followed by the introduction of retail access for all
customers by early 1998. In the event that regulation  significantly changes the
opportunity for the Company to recover its costs in the future, all or a portion
of the Company's  operations may no longer meet the criteria discussed above. In
that  event,  a  significant  write-down  of all or a portion  of the  Company's
existing   regulatory  assets  and  liabilities  could  result.  For  additional
information  respecting  the Company's  Shoreham-related  assets,  see below and
Notes 2, 3 and 11.

                                       35
<PAGE>


   
In 1996,  the Company  adopted SFAS No. 121,  "Accounting  for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" which amends SFAS
No. 71. Under SFAS No. 121,  costs which were  capitalized  in  accordance  with
regulatory  practices,  because it was probable  that future  recovery  would be
allowed by the regulator,  must be charged against current period earnings if it
appears that the criterion for  capitalization  no longer applies.  The carrying
amount  of such  assets  would be  reduced  by  amounts  for which  recovery  is
unlikely.  SFAS  No.  121  also  provides  for  the  restoration  of  previously
disallowed costs that are subsequently  allowed by a regulator.  With respect to
assets  recognized  under  SFAS No.  71 and all  other  long-lived  assets,  the
adoption  of SFAS No.  121 did not have an  effect  on the  Company's  financial
position, cash flows or results of operations.  However, if the Company had been
unable to continue to apply the  provisions of SFAS No. 71 at December 31, 1996,
the Company  estimates that  approximately  $4.6 billion would have been written
off at such time.
    

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

BASE FINANCIAL COMPONENT AND RATE MODERATION COMPONENT

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

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

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

SHOREHAM POST-SETTLEMENT COSTS

Consists of Shoreham  decommissioning  costs,  fuel  disposal  costs,  payments-
in-lieu-of-taxes,  carrying  charges  and  other  costs.  These  costs are being
capitalized and amortized and recovered through rates over a forty-year

                                       36
<PAGE>



period on a  straight-line  remaining life basis which began July 1, 1989. For a
further discussion of Shoreham post-settlement costs, see Note 2.

SHOREHAM NUCLEAR FUEL

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

UNAMORTIZED COST OF ISSUING SECURITIES

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

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

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

REGULATORY TAX ASSET AND REGULATORY TAX LIABILITY

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

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

REGULATORY LIABILITY COMPONENT

Pursuant  to the 1989  Settlement,  certain  tax  benefits  attributable  to the
Shoreham   abandonment  are  to  be  shared  between  electric   ratepayers  and
shareowners.  A regulatory  liability of approximately $794 million was recorded
in June 1989 to preserve an amount equivalent to the customer tax

                                       37
<PAGE>



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.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION

The Uniform  Systems of Accounts  defines  the  Allowance  For Funds Used During
Construction  (AFC)  as the net cost of  borrowed  funds  used for  construction
purposes and a reasonable rate of return upon the utility's equity when so used.
AFC is not an item of current cash income.  AFC is computed monthly using a rate
permitted by the FERC on a portion of construction work in progress. The average
annual AFC rate,  without  giving effect to  compounding,  was 9.02%,  9.36% and
9.18% for the years 1996, 1995 and 1994, respectively.

DEPRECIATION

The provisions for  depreciation  result from the  application of  straight-line
rates to the original cost, by groups, of depreciable properties in service. The
rates are  determined  by age-life  studies  performed  annually on  depreciable
properties. Depreciation for electric properties was equivalent to approximately
3.0% of respective  average  depreciable plant costs for each of the years 1996,
1995 and 1994.  Depreciation  for gas properties was equivalent to approximately
2.0% of respective  average  depreciable plant costs for each of the years 1996,
1995 and 1994.


                                       38
<PAGE>



CASH AND CASH EQUIVALENTS

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

LRPP RECEIVABLE/PAYABLE

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

FAIR VALUES OF FINANCIAL INSTRUMENTS

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

REVENUES

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

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

The Company's gas rate  structure  provides for a weather  normalization  clause
which reduces the impact on revenues of experiencing  weather which is warmer or
colder than normal.

FUEL COST ADJUSTMENTS

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

FEDERAL INCOME TAX

The Company  provides  deferred federal income tax with respect to certain items
of income and expense that are reported in  different  years for federal  income
tax purposes and financial statement purposes and with

                                       39
<PAGE>



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.

USE OF ESTIMATES

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

RECLASSIFICATIONS

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

NOTE 2. THE 1989 SETTLEMENT

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

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

                                       40
<PAGE>



Note 1.

In  February  1992,  the  Company  transferred  ownership  of  Shoreham to LIPA.
Pursuant to the 1989 Settlement,  the Company was required to reimburse LIPA for
all of its costs associated with the decommissioning of Shoreham.  Effective May
1,  1995,   the  Nuclear   Regulatory   Commission   (NRC)   terminated   LIPA's
possession-only  license  for  Shoreham.  The  termination  signified  the NRC's
approval  that  decommissioning  was  complete and that the site is suitable for
unrestricted use. At December 31, 1996,  Shoreham post- settlement costs totaled
approximately  $1.103 billion,  consisting of $536 million of property taxes and
payments-in-lieu-of-taxes,  and $567  million  of  decommissioning  costs,  fuel
disposal costs and all other costs incurred at Shoreham after June 30, 1989.

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

NOTE 3. RATE MATTERS

ELECTRIC

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

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

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

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

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

The Order issued in July  requested that  interested  parties file testimony and
exhibits sufficient to provide a basis for the PSC to decide whether

                                       41
<PAGE>



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

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

1995 ELECTRIC RATE ORDER

The basis of the 1995 Order included  minimizing  future electric rate increases
while continuing to provide for the recovery of the Company's  regulatory assets
and retaining  consistency  with the RMA's objective of restoring the Company to
financial health. The 1995 Order, which became effective December 1, 1994, froze
base electric rates,  reduced the Company's allowed return on common equity from
11.6% to 11.0% and modified or eliminated certain performance-based  incentives,
as discussed below.

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

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

The expense attrition and  reconciliation  component permits the Company to make
adjustments  for certain  expenses  recognizing  that these cost  increases  are
unavoidable  due to  inflation  and changes  outside the control of the Company.
Pursuant to the 1995 Order,  the Company is permitted to reconcile  expenses for
property taxes only, whereas under the original LRPP the

                                       42
<PAGE>



Company was able to reconcile expenses for wage rates,  property taxes, interest
costs and demand side management (DSM) costs.

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

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

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

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

The deferred balances resulting from the net margin and expense reconciliations,
and earned performance-based incentives are netted at the end of each rate year,
as established  under the LRPP and continued under the 1995 Order. The first $15
million of the total  deferral is recovered  from or credited to  ratepayers  by
increasing  or  decreasing  the RMC  balance.  Deferrals  in  excess  of the $15
million,  upon  approval  of the PSC,  are  refunded  to or  recovered  from the
customers through the FCA mechanism over a 12-month period.

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

                                       43
<PAGE>



while the remaining deferral of $64 million was recovered from customers.

Another  mechanism of the LRPP  provides  that earnings in excess of the allowed
return on common equity,  excluding the impacts of the various  incentive and/or
penalty programs,  are used to reduce the RMC. For the rate years ended November
30,  1996  and  1995,   the  Company  earned  $9.1  million  and  $6.2  million,
respectively,  in excess of its allowed  return on common  equity.  These excess
earnings  were applied as  reductions  to the RMC. In 1994,  the Company did not
earn in excess of its allowed return on common equity.

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

GAS

In December 1993, the PSC approved a three year gas rate settlement  between the
Company and the Staff of the PSC. The gas rate  settlement  provided  annual gas
rate increases of 4.7%, 3.8% and 3.2% for each of the three rate years beginning
December  1, 1993,  1994 and 1995,  respectively.  In the  determination  of the
revenue  requirements for the gas rate  settlement,  an allowed return on common
equity of 10.1% was used.

The gas rate  settlement also provided that earnings in excess of a 10.6% return
on common equity be shared equally  between the Company's firm gas customers and
its shareowners.  For the rate years ended November 30, 1996, 1995 and 1994, the
firm gas  customers'  portion of gas earnings in excess of the allowed return on
common  equity  totaled  approximately  $10 million,  $1 million and $7 million,
respectively.  In 1996,  the Company was granted  permission by the PSC to apply
the  customers'  portion  of the gas excess  earnings  and  associated  carrying
charges  for the 1995 and 1994 rate  years to the  recovery  of  deferred  costs
associated with  postretirement  benefits other than pensions and costs incurred
for  investigation  and remediation of manufactured  gas plant (MGP) sites.  The
Company has requested that the same treatment be granted for the  disposition of
the customers' portion of the 1996 rate year gas excess earnings.

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

NOTE 4. THE CLASS SETTLEMENT

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

The Class Settlement provides the Company's electric customers with rate

                                       44
<PAGE>



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

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

   
The Company has an undivided 18% interest in NMP2, located near Oswego, New York
which is operated by Niagara Mohawk Power Corporation (NMPC).  Ownership of NMP2
is shared by five  cotenants:  the Company  (18%),  NMPC  (41%),  New York State
Electric & Gas Corporation (18%),  Rochester Gas and Electric  Corporation (14%)
and Central Hudson Gas & Electric  Corporation  (9%). The Company's share of the
rated  capability  is  approximately  206 MW. The  Company's  net utility  plant
investment,  excluding  nuclear fuel,  was  approximately  $715 million and $740
million at December 31, 1996 and 1995,  respectively.  The accumulated provision
for  depreciation,  excluding  decommissioning  costs,  was  approximately  $169
million and $153 million at December 31, 1996 and 1995, respectively. Generation
from  NMP2  and  operating  expenses  incurred  by NMP2 are  shared  in the same
proportions  as the cotenants'  respective  ownership  interests.  The Company's
share of operating expenses is included in the corresponding  operating expenses
on its  Statement of Income.  The Company is required to provide its  respective
share of  financing  for any  capital  additions  to NMP2.  Nuclear  fuel  costs
associated  with NMP2 are being  amortized  on the basis of the quantity of heat
produced for the generation of electricity.
    

NMPC has contracted with the United States Department of Energy for the disposal
of spent nuclear fuel. The Company reimburses NMPC for its 18% share of the cost
under the contract at a rate of $1.00 per megawatt hour of net generation less a
factor to account for  transmission  line losses.  For 1996, 1995 and 1994, this
totaled $1.4 million, $1.2 million, and $1.4 million, respectively.

NUCLEAR PLANT DECOMMISSIONING

NMPC expects to commence the  decommissioning of NMP2 in 2026, shortly after the
cessation of plant operations,  using a method which provides for the removal of
all equipment and  structures  and the release of the property for  unrestricted
use. The Company's share of decommissioning  costs, based upon a "Site-Specific"
1995 study (1995  study),  is estimated to be $368 million in 2026 dollars ($148
million in 1996  dollars).  The  Company's  estimate for  decommissioning  costs
decreased in 1996 as compared to 1995  principally as a result of a reduction in
the estimated  annual  inflation  factor.  The Company's  share of the estimated
decommissioning  costs is currently  being provided for in electric rates and is
being  charged to operations  as  depreciation  expense over the service life of
NMP2. The amount of  decommissioning  costs recorded as depreciation  expense in
1996, 1995 and

                                       45
<PAGE>



1994  was  $3.9  million,  $2.3  million  and $1.6  million,  respectively.  The
accumulated  decommissioning costs collected in rates through December 31, 1996,
1995 and 1994  amounted  to  $14.9  million,  $11.0  million  and $8.7  million,
respectively.

The  Company  has  established  trust  funds  for  the  decommissioning  of  the
contaminated  portion of the NMP2 plant. It is currently estimated that the cost
to decommission the contaminated  portion of the plant will be approximately 76%
of the total  decommissioning  costs. These funds comply with regulations issued
by the NRC and the FERC  governing the funding of nuclear plant  decommissioning
costs.  The Company's  policy is to make  quarterly  contributions  to the funds
based  upon the  amount of  decommissioning  costs  reflected  in  rates.  As of
December  31,  1996,  the  balance  in these  funds,  including  reinvested  net
earnings,  was  approximately  $15.3 million.  These amounts are included on the
Company's Balance Sheet in Nonutility Property and Other Investments.  The trust
funds investment consists of U.S. Treasury debt securities and cash equivalents.
The carrying amounts of these instruments approximate fair market value.

The  Financial  Accounting  Standards  Board  issued an  exposure  draft in 1996
entitled  "Accounting for Certain  Liabilities  Related to Closure or Removal of
Long-Lived  Assets".  Under the  provisions of the exposure  draft,  the Company
would be required to change its current accounting practices for decommissioning
costs as follows: (i) the Company's share of the total estimated decommissioning
costs would be accounted  for as a liability,  based on  discounted  future cash
flows;  (ii) the  recognition of the liability for  decommissioning  costs would
result in a corresponding  increase to the cost of the nuclear plant rather than
as depreciation  expense;  and (iii) investment earnings on the assets dedicated
to the  external  decommissioning  trust fund would be  recorded  as  investment
income rather than as an increase to  accumulated  depreciation.  If the Company
was  required to record the present  value of its share of NMP2  decommissioning
costs on its Balance  Sheet as of December 31, 1996,  the Company  would have to
recognize  a  liability   and   corresponding   increase  to  nuclear  plant  of
approximately $54 million.

NUCLEAR PLANT INSURANCE

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

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

                                       46
<PAGE>



$13.6 million, per incident, through assessments of $1.8 million per year in the
event of a serious nuclear accident at NMP2 or another licensed U.S.  commercial
nuclear reactor.  These assessments are subject to periodic  inflation  indexing
and to a 5% surcharge if funds prove insufficient to pay claims.

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

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

RECENT ACTIONS OF THE NRC

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

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


                                       47
<PAGE>



NOTE 6. CAPITAL STOCK

COMMON STOCK

The  Company  has  150,000,000  shares  of  authorized  common  stock,  of which
120,784,277  were issued and 3,485  shares were held in Treasury at December 31,
1996.  The Company has 1,678,208  shares  reserved for sale through its Employee
Stock  Purchase  Plan,  2,728,486  shares  committed to the  Automatic  Dividend
Reinvestment  Plan and 97,093  shares  reserved for  conversion  of the Series I
Convertible  Preferred  Stock at a rate of $17.15 per  share.  In  addition,  in
connection  with the Share  Exchange  Agreement,  as  discussed  in Note 10, the
Company has granted Brooklyn Union the right,  under certain  circumstances,  to
purchase 23,981,964 shares of common stock at a price of $19.725 per share.

PREFERRED STOCK

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

PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION

The  aggregate  fair  value  of  redeemable   preferred   stock  with  mandatory
redemptions at December 31, 1996 and 1995 amounted to approximately $637 million
and $598  million,  respectively,  compared  to their  carrying  amounts of $640
million and $644 million, respectively. For a further discussion on the basis of
the fair value of the securities discussed above, see Note 1.

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

--------------------------------------------------------------------------------
                   Redemption Provision               Number          Redemption
  Series        Beginning           Ending          of Shares            Price
--------------------------------------------------------------------------------
    L            7/31/79           7/31/11            10,500              $100
    NN            3/1/99            3/1/19            77,700                25
    UU          10/15/99          10/15/19           112,000                25
================================================================================
The Company has the  non-cumulative  option to double the number of shares to be
redeemed  pursuant to the sinking fund  provisions in any year for the preferred
stock series NN and UU. The aggregate par value of preferred  stock  required to
be  redeemed  through  sinking  funds is $1.1  million in 1997 and 1998 and $5.8
million in each of the years 1999, 2000 and 2001.


                                       48
<PAGE>



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

--------------------------------------------------------------------------------
     Redemption           Redemption           Number of    
     Series                 Date                Shares                Amounts
--------------------------------------------------------------------------------
$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
================================================================================

PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION

The Company has the option to redeem certain series of its preferred  stock. For
the series subject to optional  redemption at December 31, 1996, the call prices
were as follows:


--------------------------------------------------------------------------------
        Series                                                    Call Price
--------------------------------------------------------------------------------
    5.00%  Series B                                                  $101

    4.25%  Series D                                                   102

    4.35%  Series E                                                   102

    4.35%  Series F                                                   102

    5 1/8% Series H                                                   102

    5 3/4% Series I - Convertible                                     100
================================================================================

PREFERENCE STOCK

At  December   31,   1996,   none  of  the   authorized   7,500,000   shares  of
nonparticipating preference stock, par value $1 per share, which ranks junior to
preferred stock, were outstanding.

NOTE 7. LONG-TERM DEBT

G&R MORTGAGE

The General and Refunding (G&R) Bonds are the Company's only outstanding secured
indebtedness.  The G&R Mortgage is a lien on substantially  all of the Company's
properties.


                                       49
<PAGE>



The annual G&R Mortgage  sinking fund  requirement  for 1996, due not later than
June 30, 1997, is estimated at $25 million.  The Company expects to satisfy this
requirement  with  retired G&R Bonds,  property  additions,  or any  combination
thereof.

1989 REVOLVING CREDIT AGREEMENT

The Company has available  through  October 1, 1997, $250 million under its 1989
Revolving Credit  Agreement (1989 RCA). In July 1996, at the Company's  request,
the amount committed by the banks participating in the facility was reduced from
$300  million  to $250  million.  This line of credit is secured by a first lien
upon the Company's accounts receivable and fuel oil inventories. At December 31,
1996,  no  amounts  were  outstanding  under the 1989  RCA.  The 1989 RCA may be
extended for  one-year  periods upon the  acceptance  by the lending  banks of a
request by the Company,  which must be  delivered to the lending  banks prior to
April 1 of each year. It is the Company's  intent to request an extension  prior
to April 1, 1997.

AUTHORITY FINANCING NOTES

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

Tender  requirements  of Authority  Financing Notes at December 31, 1996 were as
follows:

                                                       (In thousands of dollars)
--------------------------------------------------------------------------------
           Interest                                    
             Rate           Series         Principal             Tendered
--------------------------------------------------------------------------------
PCRBs       8 1/4%          1982           $ 17,200         Tendered every three
                                                            years, next tender
                                                            October 1997
             3.25%          1985 A,B        150,000         Tendered annually on
                                                            March 1

EFRBs        4.05%          1993 A           50,000         Tendered weekly
             4.00%          1993 B           50,000         Tendered weekly
             4.00%          1994 A           50,000         Tendered weekly
             4.00%          1995 A           50,000         Tendered weekly
================================================================================

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


                                       50
<PAGE>



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


--------------------------------------------------------------------------------
                            Series                              Expiration Date
--------------------------------------------------------------------------------
PCRBs                       1985 A,B                             3/16/99

EFRBs                       1993 A,B                            11/17/99

                            1994 A                              10/26/97

                            1995 A                               8/24/98
================================================================================

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.

FAIR VALUES OF LONG-TERM DEBT

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


                                             (In thousands of dollars)
--------------------------------------------------------------------------------
1996
--------------------------------------------------------------------------------
                                              Fair           Carrying
                                              Value           Amount
--------------------------------------------------------------------------------
General and Refunding Bonds                $1,571,745      $1,536,000
Debentures                                  2,271,095       2,270,000
Authority Financing Notes                     950,758         916,675
--------------------------------------------------------------------------------
Total                                      $4,793,598      $4,722,675
================================================================================

1995
--------------------------------------------------------------------------------
General and Refunding Bonds                $1,968,173       1,951,000
Debentures                                  2,245,138       2,270,000
Authority Financing Notes                     928,967         916,675
--------------------------------------------------------------------------------
Total                                      $5,142,278      $5,137,675
================================================================================

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

DEBT MATURITY SCHEDULE

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

                                       51

<PAGE>


NOTE 8. RETIREMENT BENEFIT PLANS

PENSION PLANS

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

PRIMARY PLAN

The Company's  funding  policy is to  contribute  annually to the Primary Plan a
minimum  amount  consistent  with the  requirements  of the Employee  Retirement
Income Security Act of 1974 plus such additional amounts, if any, as the Company
may determine to be appropriate  from time to time.  Pension  benefits are based
upon years of  participation in the Primary Plan and  compensation.  The Primary
Plan's funded status and amounts recognized on the Balance Sheet at December 31,
1996 and 1995 were as follows:

                                                (In thousands of dollars)
--------------------------------------------------------------------------------
                                                    1996           1995
--------------------------------------------------------------------------------
Actuarial present value of benefit obligation
  Vested benefits                              $  547,002     $  518,487
  Nonvested benefits                               55,157         54,305
--------------------------------------------------------------------------------
Accumulated Benefit Obligation                 $  602,159     $  572,792
================================================================================

Plan assets at fair value                      $  746,400     $  685,300
Actuarial present value of projected
  benefit obligation                              689,661        662,360
--------------------------------------------------------------------------------
Projected benefit obligation less
  than plan assets                                 56,739         22,940
Unrecognized net obligation                        71,085         77,831
Unrecognized net gain                            (123,759)       (97,285)
--------------------------------------------------------------------------------
Net Prepaid (Accrued) Pension Cost           $      4,065     $    3,486
================================================================================
Periodic pension cost for the Primary Plan included the following components:

                                                       (In thousands of dollars)
--------------------------------------------------------------------------------
                                             1996            1995         1994
================================================================================
Service cost - benefits
  earned during the period               $  17,384       $  15,385    $  16,465
Interest cost on projected benefit
  obligation and service cost               47,927          45,987       43,782
Actual return on plan assets               (81,165)       (102,099)     (12,431)
Net amortization and deferral               33,541          57,665      (31,633)
--------------------------------------------------------------------------------
Net Periodic Pension Cost                $  17,687       $  16,938    $  16,183
================================================================================

                                       52

<PAGE>

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

--------------------------------------------------------------------------------
                                                1996          1995         1994
--------------------------------------------------------------------------------
Discount rate                                   7.25%         7.25%        7.75%
Rate of future compensation increases           5.00%         5.00%        5.00%
Long-term rate of return on assets              7.50%         7.50%        7.50%
--------------------------------------------------------------------------------

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 the  difference  between the pension rate  allowance  and the
annual pension contributions contributed into the pension fund.

SUPPLEMENTAL PLAN

The Supplemental Plan, the cost of which is borne by the Company's  shareowners,
provides  supplemental death and retirement  benefits for officers and other key
executives without contribution from such employees.  The Supplemental Plan is a
non-qualified plan under the Internal Revenue Code. Death benefits are currently
provided by  insurance.  The provision  for plan  benefits,  which are unfunded,
totaled  approximately  $2.7  million in 1996 and $2.3  million in both 1995 and
1994.

DIRECTORS' PLAN

The Directors'  Plan provides  benefits to directors who are not officers of the
Company.  Directors  who have served in that  capacity  for more than five years
qualify as  participants  under the plan. The Directors' Plan is a non-qualified
plan under the Internal  Revenue Code.  The provision for  retirement  benefits,
which are unfunded,  totaled  approximately  $127,000,  $114,000 and $148,000 in
1996, 1995 and 1994, respectively.

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

In addition to providing pension benefits,  the Company provides certain medical
and life  insurance  benefits for retired  employees.  Substantially  all of the
Company's  employees  may  become  eligible  for these  benefits  if they  reach
retirement age after working for the Company for a minimum of five years.  These
and similar  benefits  for active  employees  are  provided by the Company or by
insurance  companies  whose  premiums are based on the benefits  paid during the
year.  Effective January 1, 1993, the Company adopted the provisions of SFAS No.
106, "Employers' Accounting for

                                       53
<PAGE>



Postretirement  Benefits  Other Than  Pensions",  which  requires the Company to
recognize the expected cost of providing  postretirement  benefits when employee
services are rendered rather than when paid. As a result, the Company,  in 1993,
recorded an accumulated  postretirement  benefit  obligation and a corresponding
regulatory asset of approximately $376 million.

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

In 1994, the Company established  Voluntary Employee's  Beneficiary  Association
trusts for union and non-union  employees for the funding of  incremental  costs
collected in rates for postretirement benefits. For the years ended December 31,
1996 and 1995, the Company funded the trusts with  approximately $18 million and
$50 million, respectively.

Accumulated postretirement benefit obligation other than pensions at December 31
was as follows:

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


                                       54
<PAGE>



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

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

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

--------------------------------------------------------------------------------
                                                     1996     1995       1994
--------------------------------------------------------------------------------
Discount rate                                        7.25%    7.25%      7.75%
Rate of future compensation increases                5.00%    5.00%      5.00%
Long-term rate of return on assets                   7.50%    7.50%        -
--------------------------------------------------------------------------------

The  assumed  health  care cost trend rates used in  measuring  the  accumulated
postretirement  benefit  obligation  at December 31, 1996 and 1995 were 8.0% and
8.5%,  respectively,  gradually declining to 6.0% in 2001 and thereafter.  A one
percentage  point increase in the health care cost trend rate would increase the
accumulated  postretirement  benefit obligation as of December 31, 1996 and 1995
by approximately $43 million and $36 million,  respectively,  and the sum of the
service  and  interest  costs  in 1996 and 1995 by $5  million  and $4  million,
respectively.


                                       55
<PAGE>



NOTE 9. FEDERAL INCOME TAX

At December 31, the significant  components of the Company's deferred tax assets
and liabilities calculated under the provisions of SFAS No. 109, "Accounting for
Income Taxes", were as follows:

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

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

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)
--------------------------------------------------------------------------------
                                              1996                       1995
--------------------------------------------------------------------------------
Regulatory Assets
1989 Settlement                         $  1,660,871               $  1,666,744
Plant items                                  125,976                    149,520
Other                                        (14,069)                   (13,881)
--------------------------------------------------------------------------------
Total Regulatory Assets                 $  1,772,778               $  1,802,383
================================================================================
Regulatory Liabilities
Carryforward credits                    $     68,421              $      82,330
Other                                         34,466                     33,730
--------------------------------------------------------------------------------
Total Regulatory Liabilities            $    102,887              $     116,060
================================================================================

                                       56
<PAGE>



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

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

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

The Company's  net operating  loss (NOL)  carryforwards  for federal  income tax
purposes are  estimated to be  approximately  $415 million at December 31, 1996.
These NOL  carryforwards are scheduled to expire in the years 2004 through 2007.
The  Company  currently  has tax  credit  carryforwards  of  approximately  $136
million.  This balance is composed of investment tax credit (ITC) carryforwards,
net of the 35%  reduction  required  by the Tax  Reform  Act of  1986,  totaling
approximately  $128  million  and  research  and  development  credits  totaling
approximately $8 million. In 1990 and 1992, the Company received Revenue Agents'
Reports disallowing certain deductions and credits claimed by the Company on its
federal income tax returns for the years 1981 through 1989. The Revenue  Agents'
Reports  proposed  ITC  adjustments  which if  sustained,  would  reduce the ITC
carryforwards to approximately $63 million.

Additionally,  the Revenue Agents' Reports reflect  proposed  adjustments to the
Company's  federal income tax returns for the years 1981 through 1989 which,  if
sustained,  would  give rise to tax  deficiencies  totaling  approximately  $227
million.  The Company believes that any such deficiencies as finally  determined
would be  significantly  less than the amounts  proposed in the Revenue  Agents'
Reports.  The Company has protested some of the proposed  adjustments  which are
presently  under review by the Regional  Appeals Office of the Internal  Revenue
Service.  If this review does not result in a settlement that is satisfactory to
the Company, the Company intends to seek a judicial review. The Company believes
that its reserves are adequate to cover any tax  deficiency  that may ultimately
be determined and that cash from operations will be

                                       57
<PAGE>



sufficient to satisfy any settlement reached. However, if necessary, the Company
will avail itself of interim financing via the 1989 RCA to meet this obligation.
The Company currently  believes that a settlement of the 1981 through 1989 years
should be reached with the Regional Appeals Office sometime in 1997.


NOTE 10. MERGER AGREEMENT WITH THE BROOKLYN UNION GAS COMPANY

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

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

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

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

Upon completion of the merger, Dr. William J. Catacosinos will become

                                       58
<PAGE>



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

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

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

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

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

NOTE 11. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

   
ELECTRIC

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.


                                       59
<PAGE>



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 expire 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 purchase power
contracts.

<TABLE>
<CAPTION>

Electric Operations                                                   (In millions of dollars)
----------------------------------------------------------------------------------------------
                                          NYPA Holtsville
                                          ---------------
                                              Other
                                   Debt       Fixed                  Firm               Total
                                 Service     Charges   Energy*   Transmission  IPP's*  Business*
                                 -------     -------   -------   ------------  ------  ---------

<S>                            <C>           <C>      <C>         <C>        <C>      <C>     
1997                           $    20.3     $  15.0  $   7.7     $  27.8    $  110.7 $  181.5
1998                                21.6        15.2      9.0        27.8       115.3    188.9
1999                                21.7        16.3      7.2        27.2       118.3    190.7
2000                                21.8        16.4      8.0        27.0       123.3    196.5
2001                                21.9        16.6     11.3        29.0       126.7    205.5
Subsequent Years                   259.9       254.9    137.0       557.4     1,161.6  2,370.8
----------------------------------------------------------------------------------------------
Total                          $   367.2     $ 334.4  $ 180.2     $ 696.2    $1,755.9 $3,333.9
Less: Imputed Interest             188.0       183.7     96.9       426.4       841.8  1,736.8
----------------------------------------------------------------------------------------------
Present Value of Payments      $   179.2     $ 150.7  $  83.3     $ 269.8    $  914.1 $1,597.1
==============================================================================================
</TABLE>

*Assumes full performance by the IPPs and NYPA.

GAS

In order to provide 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
payments even if the services are not provided  (take-or-pay.)  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 2012.


Gas Operations                                      (In millions of dollars)
--------------------------------------------------------------------------------
1997                                                       $  38.7
1998                                                          37.6
1999                                                          37.6
2000                                                          37.6
2001                                                          34.7
Subsequent Years                                             232.5
--------------------------------------------------------------------------------
Total                                                      $ 418.7
Less: Imputed Interest                                       182.1
--------------------------------------------------------------------------------
Present Value of Payments                                  $ 236.6
================================================================================
    


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<PAGE>


CONTINUOUS EMISSION MONITORING

The  Company  expended  approximately  $1  million  in 1996  to meet  continuous
emission  monitoring  requirements,  to  meet  Phase  II  nitrogen  oxide  (NOx)
reduction  requirements  under the  federal  Clean  Air Act  (CAA).  Subject  to
requirements that are expected to be promulgated in forthcoming regulations, the
Company estimates that it may be required to expend approximately $44 million by
2003 to meet Phase II and Phase III NOx reduction requirements and approximately
$2 million by 1999 to meet potential  requirements  for the control of hazardous
air  pollutants  from power plants.  The Company  believes that all of the above
costs will be recoverable through rates.

COMPETITIVE ENVIRONMENT

The electric industry  continues to undergo  fundamental  changes as regulators,
elected officials and customers seek lower energy prices.  These changes,  which
may have a  significant  impact  on future  financial  performance  of  electric
utilities,  are being  driven  by a number of  factors  including  a  regulatory
environment in which traditional  cost-based  regulation is seen as a barrier to
lower  energy  prices.  In  1996,  both  the PSC and the  FERC  continued  their
separate,  but in some cases parallel,  initiatives with respect to developing a
framework for a competitive electric marketplace.

THE ELECTRIC INDUSTRY - STATE REGULATORY ISSUES

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

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

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


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<PAGE>



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

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

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

                                       62
<PAGE>



amount of  strandable  investments  that a utility  will be permitted to recover
will depend on the particular circumstances of each utility.  Additionally,  the
Order  provided that every effort should be made by utilities to mitigate  these
costs prior to seeking recovery.

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

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

THE ELECTRIC INDUSTRY - FEDERAL REGULATORY ISSUES

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

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

                                       63
<PAGE>



become  wholesale   transmission   customers,   such  as  where  a  municipality
establishes its own electric system.

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

Order 888 required  utilities to file open access tariffs under which they would
provide transmission services, comparable to those which they provide themselves
and to third parties on a non-discriminatory basis. Additionally, utilities must
use these same tariffs for their own wholesale sales. The Company filed its open
access tariff in July 1996. In September 1996, the FERC ordered Rate Hearings on
28 utility  transmission  tariffs,  including the  Company's.  On the basis of a
preliminary  review,  the FERC was not satisfied that the tariff rates were just
and reasonable.  Settlement  discussions  have been held between the Company and
various  intervenors  concerning the Company's  transmission  rates. In December
1996,  the  parties  reached a  tentative  settlement  on the rate  issues.  The
procedural  schedule was suspended  pending filing of the settlement  agreement,
which  is  anticipated  during  the  first  quarter  of  1997.  Non-rate  issues
associated  with the Company's open access tariff have not yet been addressed by
the FERC.

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

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

It is not possible to predict the  ultimate  outcome of these  proceedings,  the
timing thereof,  or the amount, if any, of stranded costs that the Company would
recover in a  competitive  environment.  The  outcome  of the state and  federal
regulatory  proceedings  could adversely  affect the Company's  ability to apply
Statement of Financial  Accounting  Standards SFAS No. 71,  "Accounting  for the
Effects  of Certain  Types of  Regulation,"  which,  pursuant  to SFAS No.  101,
"Accounting  for  Discontinuation  of  Application  of SFAS No.  71," could then
require a  significant  write-down  of all or a  portion  of the  Company's  net
regulatory assets.

                                       64
<PAGE>

   
If the Company were unable to continue to apply the  provisions  of SFAS No. 71,
at December 31, 1996,  the Company  estimates  that  approximately  $4.6 billion
would have been written off at such time.
    

THE COMPANY'S SERVICE TERRITORY

The Company's geographic location and the limited electrical interconnections to
Long  Island  serve to  limit  the  accessibility  of its  transmission  grid to
potential  competitors  from  off the  system.  However,  the  changing  utility
regulatory  environment  has affected  the Company by  requiring  the Company to
co-exist with state and federally  mandated  competitors.  These competitors are
non-utility generators (NUGS), NYPA and Municipal Distribution Agencies (MDAs).

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

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

The increase in lost net revenues  resulted  principally  from the completion of
seven facilities that became  commercially  operational during 1996 and the full
year  operation of the IPP located at the State  University of New York at Stony
Brook, NY. The Company  estimates that in 1997, sales losses to NUGs will be 429
GWh, or approximately 1.8% of projected net revenues.

The Company believes that load losses due to NUGs have  stabilized.  This belief
is based on the fact that the  Company's  customer load  characteristics,  which
lack a significant industrial base and related large thermal load, will mitigate
load loss and thereby make cogeneration economically unattractive.

Additionally,  as mentioned  above,  the Company is required to purchase all the
power offered by QFs which in 1996 approximated

                                       65
<PAGE>



218 megawatts (MW) and in early 1995  approximated  205 MW. The increase was the
result of the SUNY Stony Brook  facility  going on line in mid 1995. The Company
estimates  that  purchases  from QFs  required by federal and state law cost the
Company $63 million and $53 million in 1996 and 1995, respectively, more than it
would have cost had the Company generated this power.

QFs have the  choice  of  pricing  sales to the  Company  at  either  the  PSC's
published  estimates of the  Company's  long-range  avoided  costs (LRAC) or the
Company's  tariff rates,  which are modified from time to time,  reflecting  the
Company's actual avoided costs.  Additionally,  until repealed in 1992, New York
State law set a minimum price of six cents per  kilowatt-hour  (kWh) for utility
purchases  of power  from  certain  categories  of QFs,  considerably  above the
Company's  avoided  cost.  The six cent minimum  continues to apply to contracts
entered into before June 1992.  The Company  believes that the repeal of the six
cent  minimum,  coupled  with  recent PSC updates  which  resulted in lower LRAC
estimates,  has significantly  reduced the economic benefits of constructing new
QFs within its service territory.

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

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

In  addition,  several  towns and  villages  on Long  Island  are  investigating
municipalization, in which customers form a government-sponsored electric supply
company.  This is one form of competition that is likely to increase as a result
of the  National  Energy  Policy Act of 1992  (NEPA).  NEPA  sought to  increase
economic  efficiency  in the  creation  and  distribution  of power by  relaxing
restrictions  on the entry of new  competitors  to the wholesale  electric power
market. NEPA does so by creating exempt wholesale generators that can sell power
in  wholesale  markets  without  the  regulatory  constraint  placed on  utility
generators  such as on the Company.  NEPA also expanded the FERC's  authority to
grant access to utility  transmission  systems to all parties who seek wholesale
wheeling  for  wholesale  competition.  While it should be noted that the FERC's
position favoring stranded cost recovery from retail turned wholesale customers

                                       66
<PAGE>



will reduce utility risk from  municipalization,  significant  issues associated
with the removal of  restrictions on wholesale  transmission  system access have
yet to be resolved.

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

In 1995,  Suffolk  County issued a request for proposal from suppliers for up to
300 MW of  power  which  the  County  would  then  sell to its  residential  and
commercial  customers.  The County has  awarded the bid to two  off-Long  Island
suppliers and has requested the Company to deliver the power.  After the Company
challenged Suffolk County's  eligibility for such service, the County petitioned
the FERC to order the Company to provide the requested transmission service.

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

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

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

                                       67
<PAGE>

ENVIRONMENTAL MATTERS

The Company is subject to federal,  state and local laws and regulations dealing
with air and  water  quality  and  other  environmental  matters.  Environmental
matters  may  expose the  Company to  potential  liabilities  which,  in certain
instances,  may be imposed without regard to fault or for historical  activities
which were lawful at the time they occurred.  The Company  continually  monitors
its  activities  in order to  determine  the  impact  of its  activities  on the
environment and to ensure compliance with various  environmental laws. Except as
set  forth  below,  no  material  proceedings  have  been  commenced  or, to the
knowledge of the Company,  are contemplated  against the Company with respect to
any matter relating to the protection of the environment.

The New York State Department of Environmental  Conservation  (DEC) has required
the  Company  and other New York  State  utilities  to  investigate  and,  where
necessary, remediate their former manufactured gas plant (MGP) sites. Currently,
the  Company  is the owner of six  pieces of  property  on which the  Company or
certain of its predecessor  companies are believed to have produced manufactured
gas. Operations at these facilities in the late 1800's and early 1900's may have
resulted in the disposal of certain waste  products on these sites.  Research is
underway  to  determine  the  existence  and  nature  of  operations  and  their
relationship, if any, to the Company or its predecessor companies.

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

In December  1996,  the Company filed a complaint in the United States  District
Court for the Southern District of New York against 14 of the Company's insurers
which issued general comprehensive  liability (GCL) policies to the Company. The
Company is seeking recovery under the GCL policies for the costs

                                       68
<PAGE>



incurred to date and future costs  associated with the clean-up of the Company's
former  MGP sites and  Superfund  sites for which the  Company  has been named a
potentially  responsible  party  (PRP).  The  Company is  seeking a  declaratory
judgment that the defendant insurers are bound by the terms of the GCL policies,
subject  to the  stated  coverage  limits,  to  reimburse  the  Company  for the
remediation costs. The outcome of this proceeding cannot yet be determined.

The Company  has been  notified by the United  States  Environmental  Protection
Agency (EPA) that it is one of many PRPs that may be liable for the  remediation
of three licensed treatment, storage and disposal sites to which the Company may
have shipped waste products and which have subsequently  become  environmentally
contaminated.

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

The Company has also been named a PRP for disposal sites in Kansas City, Kansas,
and Kansas City, Missouri.  The two sites were used by a company named PCB, Inc.
from 1982 until 1987 for the  storage,  processing,  and  treatment  of electric
equipment,  dielectric oils and materials containing PCBs. According to the EPA,
the buildings and certain soil areas outside the buildings are contaminated with
PCBs.

In 1994,  the EPA requested  certain of the large PRPs,  which  include  several
other utilities, to form a group, sign an ACO, and conduct a remediation program
for the sites under the Toxic Substances Control Act, or in the alternative,  to
perform a Superfund cleanup for the sites. The EPA has provided the Company with
documents  indicating  that the Company was  responsible for less than 1% of the
materials  that were shipped to the Missouri site. The EPA has not yet completed
compiling the documents for the Kansas site.  The Company  intends to join a PRP
Group which includes other  utilities,  which has been organized for the purpose
of developing and implementing  acceptable  remediation  programs for the sites.
The Company is currently  unable to determine its share of the cost to remediate
these sites.


                                       69
<PAGE>



In  addition,  the Company  was  notified  that it is a PRP at a Superfund  site
located  in  Farmingdale,   New  York.   Portions  of  the  site  are  allegedly
contaminated  with PCBs,  solvents and metals.  The Company was also notified by
other PRPs that it should be responsible for remediation  expenses in the amount
of approximately $100,000 associated with removing PCB-contaminated soils from a
portion of the site which formerly contained electric transformers.  The Company
is currently unable to determine its share of costs of remediation at this site.

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

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

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

In December 1996, a barge, owned and operated by a third party,  dropped anchor,
causing  extensive  damage to the Sound Cable and a release of dielectric  fluid
into the Long Island Sound.  Temporary  clamps and leak abaters have been placed
on the cables and have stopped the leaks.  Permanent  repairs are expected to be
undertaken in the late spring of 1997. The  preliminary  estimate of the cost of
these repairs is $15 million. The Company intends

                                       70
<PAGE>



to seek  recovery  from third  parties  for costs  incurred  by the Company as a
result of this incident.  The timing and amount of recovery,  if any, cannot yet
be determined. In addition, the Owners maintain insurance coverage for the Sound
Cable which the Company  believes  will be sufficient to cover any repair costs.
In any event,  costs not reimbursed by a third party or not covered by insurance
will be shared equally by the Owners.

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



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<PAGE>



NOTE 12. SEGMENTS OF BUSINESS

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

                                                        (In millions of dollars)
--------------------------------------------------------------------------------
For year ended December 31                    1996           1995         1994
--------------------------------------------------------------------------------
OPERATING REVENUES
Electric                                    $  2,467      $  2,484     $  2,481
Gas                                              684           591          586
--------------------------------------------------------------------------------
Total                                       $  3,151      $  3,075     $  3,067
================================================================================
OPERATING EXPENSES 
  (excludes federal income tax)
Electric                                    $  1,644      $  1,657     $  1,640
Gas                                              560           478          500
--------------------------------------------------------------------------------
Total                                       $  2,204      $  2,135     $  2,140
================================================================================
OPERATING INCOME 
  (before federal income tax)
Electric                                    $    823      $    827     $    842
Gas                                              124           113           85
--------------------------------------------------------------------------------
Total operating income                           947           940          927

AFC                                               (6)           (7)          (7)
Other income and deductions                      (23)          (38)         (45)
Interest charges                                 451           476          500
Federal income tax                               209           206          177
--------------------------------------------------------------------------------
Net Income                                  $    316      $    303     $    302
================================================================================

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

CONSTRUCTION AND NUCLEAR FUEL EXPENDITURES*
Electric                                    $    165      $    162     $    155
Gas                                               78            84          125
--------------------------------------------------------------------------------
Total                                       $    243      $    246     $    280
================================================================================
* Includes non-cash allowance for other funds used during construction
  and excludes Shoreham post-settlement costs.



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

                                       72
<PAGE>




NOTE 13. QUARTERLY FINANCIAL INFORMATION
(Unaudited)

                      (In thousands of dollars except earnings per common share)
--------------------------------------------------------------------------------
                                                         1996             1995
--------------------------------------------------------------------------------
OPERATING REVENUES
            For the quarter ended March 31       $     864,214     $     791,188
                                   June 30             694,602           653,824
                              September 30             849,775           875,794
                               December 31             742,104           754,322
================================================================================
OPERATING INCOME
            For the quarter ended March 31       $     190,421     $     180,875
                                   June 30             141,065           143,246
                              September 30             235,402           239,561
                               December 31             169,693           167,936
================================================================================
NET INCOME
            For the quarter ended March 31       $      81,753     $      70,299
                                   June 30              40,524            41,392
                              September 30             130,023           131,221
                               December 31              64,164            60,374
================================================================================
EARNINGS FOR COMMON STOCK
            For the quarter ended March 31       $      68,682     $      57,127
                                   June 30              27,453            28,220
                              September 30             116,972           118,069
                               December 31              51,141            47,250
================================================================================
EARNINGS PER COMMON SHARE
            For the quarter ended March 31       $         .57     $         .48
                                   June 30                 .23               .24
                              September 30                 .97               .99
                               December 31                 .43               .39
================================================================================



                                       73



<PAGE>

   
NOTE 14. EVENT SUBSEQUENT TO THE DATE OF THE REPORT OF INDEPENDENT AUDITORS
         (UNAUDITED)

LONG ISLAND POWER AUTHORITY PROPOSED TRANSACTION

On April 30, 1997, the Long Island Power Authority  (LIPA)  submitted to the New
York State Public Authorities  Control Board for approval,  unexecuted copies of
agreements  related to LIPA's  proposed  acquisition  (via the  purchase  of the
Company's common stock) of the Company's  transmission  and distribution  system
and certain other assets and  liabilities  (LIPA  Transaction).  Prior to LIPA's
acquisition of the common stock, the Company's gas assets,  electric  generating
facility assets and certain other assets and liabilities  will be transferred to
affiliates  of the  holding  company to be formed in  connection  with the Share
Exchange Agreement with Brooklyn Union.

While the specific allocation of assets and liabilities has not yet been finally
determined, it is currently contemplated that the holding company would, subject
to obtaining all required  consents,  assume the Company's (i) 7.30%  Debentures
due July 15, 1999; (ii) 8.20% Debentures due March 15, 2023; and (iii) Preferred
Stock, 7.95%, Series AA.

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.

The Company is unable to determine when or if the agreements related to the LIPA
Transaction  will be  executed  by the  parties or when or if all  consents  and
approvals required to consummate the LIPA Transaction will be obtained.
    



                                             74

<PAGE>



Report of Ernst & Young LLP, Independent Auditors



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

We have audited the  accompanying  balance sheet of Long Island Lighting Company
and the related statement of capitalization as of December 31, 1996 and 1995 and
the related  statements of income,  retained earnings and cash flows for each of
the three years in the period ended  December 31, 1996. Our audits also included
the  financial  statement  schedule  listed  in the index at Item  14(a).  These
financial  statements  and  schedule  are the  responsibility  of the  Company's
management.  Our  responsibility  is to express  an  opinion on these  financial
statements and schedule based on our audits.

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

In our opinion,  the financial  statements  referred to above present fairly, in
all material respects, the financial position of Long Island Lighting Company at
December 31, 1996 and 1995, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1996, in conformity
with generally accepted accounting principles. Also, in our opinion, the related
financial statement schedule, when considered in relation to the basic financial
statements  taken as a whole,  presents  fairly  in all  material  respects  the
information set forth therein.




Melville, New York
January 31, 1997


                                         75

<PAGE>


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
----
June    , 1997
                              Signature and Title

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

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

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

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

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

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

                               PETER O. CRISP*
                               ---------------
                           Peter O. Crisp, Director

                               VICKI L. FULLER*
                               ----------------
                          Vicki L. Fuller, Director

                             KATHERINE D. ORTEGA*
                             --------------------
                        Katherine D. Ortega, Director

                              BASIL A. PATERSON*
                              ------------------
                         Basil A. Paterson, Director

                           RICHARD L. SCHMALENSEE*
                           -----------------------
                       Richard L. Schmalensee, Director

                              GEORGE J. SIDERIS*
                              ------------------
                         George J. Sideris, Director

                               JOHN H. TALMAGE*
                               ----------------
                          John H. Talmage, Director

                           /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)

                                       74
<PAGE>


                                  SIGNATURES




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

                                    LONG ISLAND LIGHTING COMPANY

Date: June    , 1997 
                                    By:  /s/ ANTHONY NOZZOLILLO
                                    ---------------------------
                                        Anthony Nozzolillo
                                   Principal Financial Officer


            Original  powers of  attorney,  authorizing  Kathleen  A. Marion and
Anthony  Nozzolillo,  and each of them,  to sign this report and any  amendments
thereto,  as  attorney-in-fact  for each of the  Directors  and  Officers of the
Company, and a certified copy of the resolution of the Board of Directors of the
Company  authorizing  said  persons  and each of them to sign  this  report  and
amendments thereto as attorney-in-fact for any Officers signing on behalf of the
Company,  have been filed with the Securities and Exchange Commission as Exhibit
24 to the Company's Form 10-K for the Year Ended December 31, 1996.



                                       75