UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549

                                    FORM 10-Q

           [X]     QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

           [ ]       For the quarterly period ended March 31, 2003
                TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                        For the Transition period from to

                         Commission file number 1-14161

                               KEYSPAN CORPORATION
             (Exact name of Registrant as specified in its Charter)

           New York                                    11-3431358
           --------                                     ----------
(State or other jurisdiction of                (IRS Employer Identification No.)
incorporation or organization)



                 One MetroTech Center, Brooklyn, New York 11201
              175 East Old Country Road, Hicksville, New York 11801
             ------------------------------------------------------
               (Address of principal executive offices) (Zip Code)

                            (718) 403-1000 (Brooklyn)
                           (631) 755-6650 (Hicksville)
                           ---------------------------
              (Registrant's telephone number, including area code)

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. [X]

Indicate  by check mark  whether  the  registrant  is an  accelerated  filer (as
defined in Rule 12b-2 of the Exchange Act). [X]

                      APPLICABLE ONLY TO CORPORATE ISSUERS:

Indicate the number of shares  outstanding  of each of the  issuer's  classes of
common stock, as of the latest practicable date.

  Class of Common Stock                         Outstanding at April 16, 2003
  ---------------------                         -----------------------------
     $.01 par value                                     157,321,304



<PAGE>




                      KEYSPAN CORPORATION AND SUBSIDIARIES

                                      INDEX
                                      -----

                           Part I.   FINANCIAL INFORMATION              Page No.
                                                                        --------

Item 1. Financial Statements

         Consolidated Balance Sheet -
         March 31, 2003 and December 31, 2002                               3

         Consolidated Statement of Income -
         Three Months Ended March 31, 2003 and 2002
                                                                            5

         Consolidated Statement of Cash Flows -
         Three Months Ended March 31, 2003 and 2002                         6

         Notes to Consolidated Financial Statements                         7

Item 2. Management's Discussion and Analysis of Financial
         Condition and Results of Operations                               31

Item 3. Quantitative and Qualitative Disclosures
         About Market Risk                                                 56

                           Part II.   OTHER INFORMATION

Item 1. Legal Proceedings                                                  60

Item 6. Exhibits and Reports on Form 8-K                                   60

Signatures                                                                 62





                                       2
<PAGE>



<TABLE>

                           CONSOLIDATED BALANCE SHEET
                                   (Unaudited)
<CAPTION>

-------------------------------------------------------------------------------------------
(In Thousands of Dollars)                            March 31, 2003     December 31, 2002
-------------------------------------------------------------------------------------------

ASSETS
<S>                                                        <C>                 <C>
Current Assets
    Cash and temporary cash investments                  $    244,062         $    170,617
    Accounts receivable                                     1,626,587            1,122,022
    Unbilled revenue                                          505,477              473,060
    Allowance for uncollectible accounts                      (79,949)             (63,029)
    Gas in storage, at average cost                            87,569              297,060
    Material and supplies, at average cost                    121,221              113,519
    Other                                                      63,386               93,980
                                                    ------------------ --------------------
                                                            2,568,353            2,207,229
                                                    ------------------ --------------------

Investments and  Other                                        268,878              265,977

Property
    Gas                                                     6,202,733            6,124,281
    Electric                                                2,027,866            1,974,352
    Other                                                     395,732              394,374
    Accumulated depreciation                               (2,807,495)          (2,740,516)
    Gas exploration and production, at cost                 2,567,738            2,438,998
    Accumulated depletion                                  (1,010,770)            (973,889)
                                                    ------------------ --------------------
                                                            7,375,804            7,217,600
                                                    ------------------ --------------------

Deferred Charges
    Regulatory assets                                         444,388              438,516
    Goodwill, net of amortization                           1,789,166            1,789,751
    Other                                                     684,217              695,233
                                                    ------------------ --------------------
                                                            2,917,771            2,923,500
                                                    ------------------ --------------------

Total Assets                                             $ 13,130,806         $ 12,614,306
                                                    ================== ====================

-------------------------------------------------------------------------------------------
</TABLE>


        See accompanying Notes to the Consolidated Financial Statements.



                                       3
<PAGE>

<TABLE>

                           CONSOLIDATED BALANCE SHEET
                                   (Unaudited)
<CAPTION>

--------------------------------------------------------------------------------------------
(In Thousands of Dollars)                           March 31, 2003     December 31, 2002
--------------------------------------------------------------------------------------------

LIABILITIES AND CAPITALIZATION
<S>                                                        <C>                   <C>
Current Liabilities
    Current Redemption of long-term debt                 $     11,414          $     11,413
    Accounts payable and other liabilities                  1,212,406             1,061,649
    Commercial paper                                          677,332               915,697
    Dividends payable                                          71,166                64,714
    Taxes accrued                                             254,687                51,276
    Customer deposits                                          38,876                38,387
    Interest accrued                                           85,416                77,092
                                                    ------------------ ---------------------
                                                            2,351,297             2,220,228
                                                    ------------------ ---------------------

Deferred Credits and Other Liabilities
    Regulatory liabilities                                     72,230                84,479
    Deferred income tax                                       887,708               877,013
    Postretirement benefits and other reserves                867,681               759,731
    Other                                                     205,934               189,912
                                                    ------------------ ---------------------
                                                            2,033,553             1,911,135
                                                    ------------------ ---------------------

Commitments and Contingencies (See Note 8)                          -                     -

Capitalization
    Common stock                                            3,481,607             3,005,354
    Retained earnings                                         694,630               522,835
    Other comprehensive income                               (114,221)             (108,423)
    Treasury stock                                           (448,867)             (475,174)
                                                    ------------------ ---------------------
         Total common shareholders' equity                  3,613,149             2,944,592
    Preferred stock                                            83,849                83,849
    Long-term debt                                          4,740,231             5,224,081
                                                    ------------------ ---------------------
Total Capitalization                                        8,437,229             8,252,522
                                                    ------------------ ---------------------

Minority Interest in Subsidiary Companies                     308,727               230,421
                                                    ------------------ ---------------------
Total Liabilities and Capitalization                     $ 13,130,806          $ 12,614,306
                                                    ================== =====================

--------------------------------------------------------------------------------------------
</TABLE>


        See accompanying Notes to the Consolidated Financial Statements.




                                       4
<PAGE>

<TABLE>

                        CONSOLIDATED STATEMENT OF INCOME
                                   (Unaudited)
<CAPTION>

------------------------------------------------------------------------------------------
                                                          Three Months Ended March 31,
(In Thousands of Dollars, Except Per Share Amounts)           2003             2002
------------------------------------------------------------------------------------------
Revenues
    <S>                                                       <C>              <C>
     Gas Distribution                                        $ 1,832,701      $ 1,222,966
     Electric Services                                           334,394          314,685
     Energy Services                                             192,371          241,559
     Gas Exploration and Production                              127,847           76,926
     Energy Investments                                           25,212           17,442
                                                        ----------------------------------
Total Revenues                                                 2,512,525        1,873,578
                                                        ----------------------------------
Operating Expenses
     Purchased gas for resale                                  1,196,165          649,360
     Fuel and purchased power                                     97,522           84,372
     Operations and maintenance                                  498,189          498,075
     Depreciation, depletion and amortization                    144,971          125,997
     Operating taxes                                             124,713          113,902
                                                        ----------------------------------
Total Operating Expenses                                       2,061,560        1,471,706
                                                        ----------------------------------

Operating Income                                                 450,965          401,872
                                                        ----------------------------------
Other Income and (Deductions)
     Interest charges                                            (68,939)         (72,612)
     Gain on sale of subsidiary stock                             19,020                -
     Cost of debt redemption                                     (18,194)               -
     Minority interest                                           (18,054)          (4,431)
     Other                                                        21,126           15,111
                                                        ----------------------------------
Total Other Income and (Deductions)                              (65,041)         (61,932)
                                                        ----------------------------------
Earnings Before Income Taxes                                     385,924          339,940
Income Taxes
     Current                                                     129,575          (68,292)
     Deferred                                                     13,258          193,601
                                                        ----------------------------------
Total Income Taxes                                               142,833          125,309
                                                        ----------------------------------

Earnings Before Change in Accounting Principle                   243,091          214,631

Cummulative Effect of Change in Accounting Principle                 174                -
                                                        ----------------------------------

Net Income                                                       243,265          214,631
Preferred stock dividend requirements                              1,461            1,476
                                                        ----------------------------------
Earnings for Common Stock                                    $   241,804      $   213,155
                                                        ==================================
Basic Earnings Per Share:
  Before Change in Accounting Principle,
         less preferred stock dividends                      $      1.54      $      1.52
  Change in Accounting Principle                                       -                -
                                                        ----------------------------------
Basic Earnings Per Share                                     $      1.54      $      1.52
                                                        ==================================
Diluted Earnings Per Share
  Before Change in Accounting Principle,
         less preferred stock dividends                      $      1.53      $      1.51
  Change in Accounting Principle                                       -                -
                                                        ----------------------------------
Diluted Earnings Per Share                                   $      1.53      $      1.51
                                                        ==================================
Average Common Shares Outstanding (000)                          156,886          140,039
Average Common Shares Outstanding - Diluted (000)                158,045          141,012
------------------------------------------------------------------------------------------
</TABLE>


        See accompanying Notes to the Consolidated Financial Statements.



                                       5
<PAGE>

<TABLE>

                      CONSOLIDATED STATEMENT OF CASH FLOWS
<CAPTION>

---------------------------------------------------------------------------------------
(Unaudited)                                                 Three Months Ended March 31,
(In Thousands of Dollars)                                       2003           2002
---------------------------------------------------------------------------------------
<S>                                                           <C>             <C>
Operating Activities
Net Income                                                   $ 243,265       $ 214,631
Adjustments to reconcile net income to net
      cash provided by (used in) operating activities
    Depreciation, depletion and amortization                   144,971         125,997
    Deferred income tax                                         13,258          19,822
    Income from equity investments                              (6,425)         (4,154)
    Amortization of interest rate swap                          (2,500)              -
Changes in assets and liabilities
    Accounts receivable                                       (520,062)       (109,904)
    Materials and supplies, fuel oil and gas in storage        201,789         181,101
    Accounts payable and other liabilities                     349,722        (219,144)
    Interest accrued                                             8,324          43,874
    Other                                                       57,547          80,326
                                                      ---------------------------------
Net Cash Provided by Operating Activities                      489,889         332,549
                                                      ---------------------------------
Investing Activities
    Construction expenditures                                 (220,779)       (244,153)
    Proceeds from monetization of Houston Exploration           79,200               -
                                                      ---------------------------------
Net Cash Used in Investing Activities                         (141,579)       (244,153)
                                                      ---------------------------------
Financing Activities
    Treasury stock issued                                       26,307          34,058
    Equity Issuance                                            473,573               -
    Issuance of long-term debt                                  39,161          10,401
    Payment of long-term debt                                  (72,565)        (25,356)
    Payment of commercial paper                               (238,365)         (9,947)
    Redemption of Promissory Notes                            (447,005)              -
    Preferred stock dividends paid                              (1,461)         (1,476)
    Common stock dividends paid                                (63,557)        (62,207)
    Other                                                        9,047          (2,420)
                                                      ---------------------------------
Net Cash Used in Financing Activities                         (274,865)        (56,947)
                                                      ---------------------------------
Net Increase in Cash and Cash Equivalents                    $  73,445       $  31,449
Cash and Cash Equivalents at Beginning of Period               170,617         159,252
                                                      ---------------------------------
Cash and Cash Equivalents at End of Period                   $ 244,062       $ 190,701
                                                      =================================

---------------------------------------------------------------------------------------
</TABLE>

Cash equivalents are short-term  marketable securities purchased with maturities
of three months or less that were carried at cost which approximates fair value.

        See accompanying Notes to the Consolidated Financial Statements.




                                       6
<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

KeySpan  Corporation  (referred to in the Notes to the  Financial  Statements as
"KeySpan,"  "we,"  "us" and "our") is a  registered  holding  company  under the
Public  Utility  Holding  Company  Act of 1935,  as amended  ("PUHCA").  KeySpan
operates six regulated  utilities that distribute  natural gas to  approximately
2.5 million  customers  in New York City,  Long  Island,  Massachusetts  and New
Hampshire,  making  KeySpan the fifth  largest gas  distribution  company in the
United States and the largest in the Northeast. We also own and operate electric
generating  plants in Nassau and  Suffolk  Counties on Long Island and in Queens
County in New York City and are the largest  investor owned electric  generation
operator in New York State.  Under contractual  arrangements,  we provide power,
electric  transmission  and  distribution  services,  billing and other customer
services for  approximately  one million  electric  customers of the Long Island
Power Authority  ("LIPA").  KeySpan's other subsidiaries are involved in gas and
oil  exploration  and  production;  gas  storage;  wholesale  and retail gas and
electric marketing;  appliance service; plumbing;  heating,  ventilation and air
conditioning  and other  mechanical  services;  large  energy-system  ownership,
installation  and  management;  engineering and consulting  services;  and fiber
optic  services.  We also invest and  participate in the development of, natural
gas pipelines, natural gas processing plants, and other energy-related projects,
domestically and internationally. (See Note 2 "Business Segments" for additional
information on each operating segment.)

1. BASIS OF PRESENTATION

In our opinion,  the accompanying  unaudited  Consolidated  Financial Statements
contain all adjustments necessary to present fairly KeySpan's financial position
as of March 31, 2003,  and the results of operations  for the three months ended
March 31, 2003 and March 31,  2002,  as well as cash flows for the three  months
ended March 31, 2003 and March 31, 2002. The accompanying  financial  statements
should be read in conjunction  with the  consolidated  financial  statements and
notes  included  in  KeySpan's  Annual  Report  on Form 10K for the  year  ended
December 31, 2002. The December 31, 2002  financial  statement  information  has
been  derived from the 2002 audited  financial  statements.  Income from interim
periods may not be indicative of future results. Certain  reclassifications were
made to conform  prior  period  financial  statements  with the  current  period
financial statement presentation.

Basic  earnings per share ("EPS") is calculated by dividing  earnings  available
for  common  stock by the  weighted  average  number of  shares of common  stock
outstanding  during  the  period.  No  dilution  for  any  potentially  dilutive
securities is included.  Diluted EPS assumes the  conversion of all  potentially
dilutive  securities and is calculated by dividing earnings available for common
stock,  as  adjusted,  by the sum of the  weighted  average  number of shares of
common stock outstanding plus all potentially dilutive securities.





                                       7
<PAGE>


We have approximately 2.1 million common stock options  outstanding at March 31,
2003,  that  were not  included  in the  calculation  of  diluted  EPS since the
exercise price associated with these options was greater than the average market
price of our common stock.


Under the requirements of Statement of Financial  Accounting  Standards ("SFAS")
No. 128, "Earnings Per Share" our basic and diluted EPS are as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
                                                            Three Months Ended March 31,
(In Thousands of Dollars, Except Per Share Amounts)           2003             2002
------------------------------------------------------------------------------------------
<S>                                                             <C>              <C>
Earnings for common stock                                      $ 241,804        $ 213,155
Interest savings on convertible preferred stock                      133              142
Houston Exploration dilution                                         (87)             (96)
------------------------------------------------------------------------------------------
Earnings for common stock - adjusted                           $ 241,850        $ 213,201
------------------------------------------------------------------------------------------
Weighted average shares outstanding (000)                        156,886          140,039
Add dilutive securities:
Options                                                              931              729
Convertible preferred stock                                          228              244
------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution    158,045          141,012
------------------------------------------------------------------------------------------
Basic earnings per share                                       $    1.54        $    1.52
------------------------------------------------------------------------------------------
Diluted earnings per share                                     $    1.53        $    1.51
------------------------------------------------------------------------------------------
</TABLE>


2. BUSINESS SEGMENTS

We have four reportable segments:  Gas Distribution,  Electric Services,  Energy
Services and Energy Investments.

The Gas  Distribution  segment  consists of six gas  distribution  subsidiaries.
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution services to
customers in the New York City Boroughs of Brooklyn,  Queens and Staten  Island.
KeySpan Energy Delivery Long Island ("KEDLI") provides gas distribution services
to customers in the Long Island  Counties of Nassau and Suffolk and the Rockaway
Peninsula of Queens County. The remaining gas distribution subsidiaries,  Boston
Gas Company,  Colonial Gas Company,  Essex Gas Company and  EnergyNorth  Natural
Gas,  Inc.,  collectively  referred to as KeySpan  Energy  Delivery  New England
("KEDNE"),  provide gas distribution  service to customers in Massachusetts  and
New Hampshire.

The  Electric  Services  segment  consists  of  subsidiaries  that:  operate the
electric  transmission  and  distribution  system owned by LIPA; own and provide
capacity to and produce energy for LIPA from our generating  facilities  located
on Long  Island;  and  manage  fuel  supplies  for LIPA to fuel our Long  Island
generating facilities.  These services are provided in accordance with long-term
service  contracts  having remaining terms that range from four to twelve years.
Also, in the summer of 2002, we placed two 79.9 megawatt  generating  facilities
into service;  the capacity of and energy from these facilities are dedicated to
LIPA under 25 year  contracts.  The  Electric  Services  segment  also  includes


                                       8
<PAGE>

subsidiaries that own, lease and operate the 2,200 megawatt  Ravenswood electric
generation facility ("Ravenswood facility"), located in Queens, New York. All of
the energy,  capacity and ancillary services related to the Ravenswood  facility
is sold to the New York Independent System Operator ("NYISO") energy markets.

The Energy  Services  segment  includes  companies  that provide  energy-related
services  to  customers  located  within  the New York  City  metropolitan  area
including New Jersey and  Connecticut,  as well as Rhode  Island,  Pennsylvania,
Massachusetts and New Hampshire,  through the following three lines of business:
(i) Home Energy Services,  which provides residential customers with service and
maintenance of energy systems and appliances, as well as the retail marketing of
electricity  to  residential  and  small  commercial  customers;  (ii)  Business
Solutions, which provides plumbing, heating,  ventilation,  air conditioning and
mechanical services, as well as operation and maintenance,  design,  engineering
and consulting services to commercial and industrial customers;  and (iii) Fiber
Optic Services,  which provides  various  services to carriers of voice and data
transmission on Long Island and in New York City.

The Energy  Investments  segment  consists of our gas exploration and production
investments, as well as certain other domestic and international  energy-related
investments.  Our gas exploration and production subsidiaries are engaged in gas
and oil  exploration  and  production,  and the  development  and acquisition of
domestic natural gas and oil properties.  These  investments  consist of our 56%
equity interest in The Houston Exploration Company ("Houston  Exploration"),  an
independent  natural  gas  and oil  exploration  company,  as  well  as  KeySpan
Exploration and Production,  LLC, our wholly owned subsidiary engaged in a joint
venture with Houston Exploration. On February 26, 2003, we reduced our ownership
interest in Houston  Exploration  from 66% to 56% following the  repurchase,  by
Houston  Exploration,  of three million shares of common stock owned by KeySpan.
We realized  net  proceeds of $79 million in  connection  with this  repurchase.
KeySpan follows an accounting policy of income statement  recognition for Parent
company  gains  or  losses  from  common  stock  transactions  initiated  by its
subsidiaries.  As a  result,  KeySpan  realized  a gain of $19  million  on this
transaction.  Income  taxes  were  not  provided,  since  this  transaction  was
structured as a return of capital.

KeySpan  subsidiaries  also  hold a 20%  equity  interest  in the  Iroquois  Gas
Transmission  System  LP, a  pipeline  that  transports  Canadian  gas supply to
markets  in the  Northeastern  United  States;  a 50%  interest  in the  Premier
Transmission  Pipeline  and a 24.5%  interest in Phoenix  Natural  Gas,  both in
Northern  Ireland;  and investments in certain  midstream  natural gas assets in
Western Canada through  KeySpan  Canada.  With the exception of KeySpan  Canada,
which is  consolidated  in our  financial  statements,  these  subsidiaries  are
accounted  for under the equity  method.  Accordingly,  equity income from these
investments is reflected in Other Income and  (Deductions)  in the  Consolidated
Statement of Income.



                                       9
<PAGE>

The  accounting  policies  of the  segments  are the same as those  used for the
preparation of the Consolidated Financial Statements. The segments are strategic
business units that are managed separately because of their different  operating
and regulatory environments.  Operating results of our segments are evaluated by
management on an operating  income basis. At March 31, 2003, the total assets of
each reportable  segment have not changed  materially from those levels reported
at December 31, 2002. The reportable segment information is as follows:

<TABLE>
<CAPTION>

-----------------------------------------------------------------------------------------------------------------------------------
                                                                                 Energy Investments
                                                                           --------------------------
                                                                               Gas
                                                                            Exploration
                                         Gas         Electric     Energy        and          Other
(InThousands of Dollars)            Distribution     Services    Services   Production     Investments  Eliminations   Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>             <C>         <C>         <C>            <C>           <C>          <C>
Three Months Ended March 31, 2003
Unaffiliated revenue                  1,832,701       334,394     192,371     127,847        25,212             -       2,512,525
Intersegment revenue                          -            25       1,426           -         1,252        (2,703)              -
Operating Income                        364,937        39,670      (9,148)     55,590         4,467        (4,551)        450,965

Three Months Ended March 31, 2002
Unaffiliated revenue                  1,222,966       314,685     241,559      76,926        17,442             -       1,873,578
Intersegment revenue                          -            25           -           -           194          (219)              -
Operating Income                        331,019        61,494      (9,358)     19,825           551        (1,659)        401,872
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

Eliminating  items  include  intercompany   interest  income  and  expense,  the
elimination  of certain  intercompany  accounts,  as well as  activities  of our
corporate and administrative areas.

Because of the nature of our Electric Services  business,  electric revenues are
derived  from two  large  customers  - the NYISO  and  LIPA.  Electric  Services
revenues from these customers of $334.4 million and $314.7 million for the three
months ended March 31, 2003 and 2002 represent  approximately 13% and 17% of our
consolidated revenues, respectively.


3. COMPREHENSIVE INCOME

The table below indicates the components of comprehensive income.
<TABLE>
<CAPTION>

--------------------------------------------------------------------------------------------------------------------
                                                                                     Three Months Ended March 31,
(In Thousands of Dollars)                                                             2003                   2002
--------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>                     <C>
Net Income                                                                        $ 243,265               $ 214,631
--------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
  Net losses (gains) on derivative instruments                                        2,354                  (7,287)
  Foreign currency translation adjustments                                            9,753                  (1,713)
  Unrealized gains (losses) on marketable securities                                 (3,156)                 (1,041)
  Accrued unfunded pension obligation                                                     -                  (1,132)
  Unrealized losses on derivative financial instruments                             (14,749)                (23,785)
--------------------------------------------------------------------------------------------------------------------
Other comprehensive loss, net of tax                                                 (5,798)                (34,958)
--------------------------------------------------------------------------------------------------------------------
Comprehensive Income                                                              $ 237,467               $ 179,673
--------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
  Net losses (gains) on derivative instruments                                        1,267               $  (3,924)
  Foreign currency translation adjustments                                            5,252                    (923)
  Unrealized gains (losses) on marketable securities                                 (1,699)                   (560)
  Accrued unfunded pension obligation                                                     -                    (610)
  Unrealized losses on derivative financial instruments                              (7,942)                (12,807)
--------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense                                                       $  (3,122)              $ (18,824)
--------------------------------------------------------------------------------------------------------------------
</TABLE>




                                       10
<PAGE>


4. CAPITAL STOCK

On January 17, 2003,  we issued 13.9 million  shares of common stock in a public
offering that generated net proceeds of approximately  $473 million.  All shares
were offered by KeySpan pursuant to the effective shelf  registration  statement
filed with the Securities and Exchange Commission ("SEC").

5. LONG-TERM DEBT

In connection with the KeySpan/Long  Island Lighting Company ("LILCO")  business
combination in 1998,  KeySpan and certain of its subsidiaries  issued promissory
notes to LIPA to support certain debt  obligations  assumed by LIPA. At December
31, 2002, the remaining  principal amount of promissory notes issued to LIPA was
approximately  $600  million.  To  mitigate  the  dilutive  effect of the equity
issuance previously  mentioned in Note 4, in March 2003, we called approximately
$447  million  aggregate  principal  amount  of  such  promissory  notes  at the
applicable  redemption prices plus accrued and unpaid interest through the dates
of redemption.  We applied the  provisions of Statement of Financial  Accounting
Standards ("SFAS") 145 "Rescission of FASB Statement No. 4, 44 and 64, Amendment
of FASB Statement No. 13, and Technical  Corrections" and recorded an expense of
$18.2  million,  reflecting  redemption  costs,  as  well  as the  write-off  of
previously deferred debt issuance costs. This expense has been recorded in Other
Income and Deductions in the Consolidated Statement of Income.

In April 2003, we issued $300 million of  medium-term  and long-term  debt.  The
debt was issued in the  following  two series:  (i) $150 million 4.65% Notes due
2013; and (ii) $150 million 5.875% Notes due 2033. The proceeds of this issuance
were used to pay down outstanding commercial paper.

KeySpan has the ability under the Public Utility  Holding  Company Act ("PUHCA")
to issue up to $2.2 billion of securities  through December 31, 2003.  Following
the recent common stock offering previously mentioned and shares of common stock
expected to be issued for employee benefit and dividend  reinvestment  plans, we
have  approximately  $25 million  available  for the issuance of new  securities
under our current PUHCA  authorization.  However,  the issuance of securities in
connection with the redemption of existing securities  (including the promissory
notes  discussed   previously)  is  permitted  under  our  PUHCA   authorization
notwithstanding  the foregoing limit. We intend to seek  authorization  from the
SEC in the near  term to  enable us to among,  other  things,  issue  additional
securities in an aggregate  amount not yet  determined.  It is anticipated  that
this authorization will be obtained before the end of the year.



                                       11
<PAGE>


6. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

Financially-Settled  Commodity Derivative Instruments: From time to time KeySpan
has utilized  derivative  financial  instruments,  such as futures,  options and
swaps,  for the purpose of hedging exposure to commodity price risk and to hedge
the cash flow  variability  associated  with a portion of peak  electric  energy
sales.

Houston Exploration has utilized collars,  as well as  over-the-counter  ("OTC")
swaps, to hedge the cash flow variability  associated with forecasted sales of a
portion of its natural gas and oil  production.  As of March 31,  2003,  Houston
Exploration has hedged  approximately 67% and 38% of its estimated 2003 and 2004
gas  production,  respectively.  Further,  Houston  Exploration  may enter  into
additional  derivative positions for 2004. Houston Exploration used standard New
York Mercantile  Exchange  ("NYMEX") futures prices and published  volatility in
its Black-Scholes calculation to value its outstanding derivatives.  The maximum
length  of time  over  which  Houston  Exploration  has  hedged  such  cash flow
variability  associated  with: (i) forecasted  natural gas production is through
December  2004;  and (ii)  forecasted  oil  production is through June 2003. The
estimated amount of losses associated with such derivative  instruments that are
reported in Other Comprehensive  Income and that are expected to be reclassified
into  earnings over the next twelve  months is $52.2  million,  or $33.9 million
after-tax.

With respect to price exposure associated with fuel purchases for the Ravenswood
facility,  KeySpan  employs  standard  NYMEX  natural gas futures  contracts and
over-the-counter  financially  settled natural gas basis swaps to hedge the cash
flow  variability of a portion of forecasted  purchases of natural gas.  KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow  variability of a portion of forecasted  purchases of fuel oil that will be
consumed at the  Ravenswood  facility.  The maximum length of time over which we
have hedged cash flow variability  associated with: (i) forecasted  purchases of
natural gas is through October 2003; and (ii)  forecasted  purchases of fuel oil
is through April 2004. We used  standard  NYMEX futures  prices to value the gas
futures contracts and industry published oil indices for number 6 grade fuel oil
to value the oil swap contracts.  The estimated  amount of gains associated with
all such derivative  instruments that are reported in Other Comprehensive Income
and that are  expected to be  reclassified  into  earnings  over the next twelve
months is $3.0 million, or $2.0 million after-tax.

Our retail gas and electric marketing subsidiary,  our domestic gas distribution
operations  and KeySpan  Canada employ NYMEX  natural gas futures  contracts and
natural gas swaps to lock-in a price for expected  future natural gas purchases.
As applicable,  we used standard  NYMEX futures prices and relevant  natural gas
indices to value the  outstanding  contracts.  The  maximum  length of time over
which we have hedged such cash flow  variability  is through  October 2004.  The
estimated amount of gains  associated with such derivative  instruments that are
reported in Other Comprehensive  Income and that are expected to be reclassified
into  earnings  over the next twelve  months is $3.7  million,  or $2.4  million
after-tax.


                                       12
<PAGE>


We have also engaged in the use of  cash-settled  swap  instruments to hedge the
cash flow variability  associated with (i) a portion of forecasted peak electric
energy sales from the Ravenswood  facility and (ii) forecasted sales of Unforced
Capacity  ("UCAP") to the NYISO.  The maximum  length of time over which we have
hedged cash flow variability is through March 2004. We used  NYISO-location zone
published  indices as well as  published  NYISO  bidding  prices to value  these
outstanding  derivatives.  The estimated  amount of losses  associated with such
derivative  instruments that are reported in Other Comprehensive Income and that
are expected to be  reclassified  into  earnings  over the next twelve months is
$0.9 million, or $0.6 million after-tax.

KeySpan Canada also employs  electricity  swap contracts to lock-in the purchase
price  of  electricity  needed  to  operate  its gas  processing  plants.  These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $1.1 million, or $0.7 million after-tax.

The following  tables set forth selected  financial data  associated  with these
derivative financial  instruments noted above that were outstanding at March 31,
2003.
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
                                     Year of       Volumes                              Fixed          Current        Fair Value
             Type of Contract        Maturity        mmcf       Floor $   Ceiling $     Price $         Price $         ($000)
--------------------------------------------------------------------------------------------------------------------------------
                    Gas
<S>                                    <C>          <C>         <C>         <C>      <C>             <C>               <C>
Collars                                 2003         41,250      3.48        4.92               -     5.06 - 5.30       (24,881)
                                        2004         36,600      3.75        5.05               -     4.33 - 5.38       (10,200)

Swaps/Futures - Short Natural Gas       2003         11,214         -           -     3.19 - 3.57     4.22 - 5.30       (21,519)

Swaps/Futures - Long Natural Gas        2003          4,550         -           -     3.14 - 4.92     5.06 - 5.30         6,249
                                        2004             90         -           -     3.49 - 4.35     3.90 - 4.40            31

--------------------------------------------------------------------------------------------------------------------------------
                                                     93,704                                                             (50,320)
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                       13
<PAGE>


<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
                                  Year of         Volumes                                                     Fair Value
      Type of Contract            Maturity        Barrels        Fixed Price $           Current Price $       ($000)
-------------------------------------------------------------------------------------------------------------------------------
             Oil
<S>                                   <C>        <C>             <C>                     <C>                  <C>
Swaps - Short Fuel Oil                 2003        91,000                 29.70           28.03 - 30.42        (116)

Swaps - Long Fuel Oil                  2003        81,697         20.60 - 23.50           26.41 - 33.58         639
                                       2004         5,548         20.50 - 23.70           25.49 - 26.07          22
-------------------------------------------------------------------------------------------------------------------------------
                                                  178,245                                                       545
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
                             Year of                                       Fixed Margin/                               Fair Value
    Type of Contract         Maturity      Capacity          MWh               Price $            Current Price $        ($000)
---------------------------------------------------------------------------------------------------------------------------------
       Electricity
<S>                                          <C>           <C>             <C>                    <C>                    <C>
Swaps - Energy                 2003              -          447,200         30.50 - 61.91          36.02 - 49.52            (647)
                               2004                          99,200                 14.00          23.56 - 32.41          (1,488)

Swaps - Capacity               2003            100                -                  7.75                   7.00              75
---------------------------------------------------------------------------------------------------------------------------------
                                               100          546,400                                                       (2,060)
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>


------------------------------------------------------------------------------
                                                                        2003
Change in Fair Value of Derivative Instruments                         ($000)
------------------------------------------------------------------------------
Fair value of contracts at January 1,                               $ (32,628)
Losses on contracts realized                                            3,621
Fair value of new contracts when entered into during period                 -
(Decrease) in fair value of all open contracts                        (22,828)
------------------------------------------------------------------------------
Fair value of contracts outstanding at March 31,                    $ (51,835)
------------------------------------------------------------------------------




                                       14
<PAGE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
-----------------------------------------------------------------------------------------------------
                                                              Fair Value of Contracts
-----------------------------------------------------------------------------------------------------
                                                       Maturity          Maturity           Total
Sources of Fair Value                                    2003              2004           Fair Value
-----------------------------------------------------------------------------------------------------
<S>                                                      <C>                <C>             <C>
Prices actively quoted                                  $ (29,898)         $     31        $ (29,867)
Prices provided by external sources                           417                 -              417
Prices based on models and
    other valuation methods                               (16,423)           (4,424)         (20,847)
Local published indicies                                   (1,538)                -           (1,538)
-----------------------------------------------------------------------------------------------------
                                                        $ (47,442)         $ (4,393)       $ (51,835)
-----------------------------------------------------------------------------------------------------
</TABLE>


NYMEX  futures  are also used to  economically  hedge the cash flow  variability
associated  with the  purchase  of fuel for a  portion  of our  fleet  vehicles.
Further,  KeySpan  Canada has a  portfolio  of  financially-settled  natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i)  synthetically  fix the price that is paid or received by
KeySpan  Canada for  certain  physical  transactions  involving  natural gas and
natural gas liquids and (ii) transfer the price exposure of such  instruments to
counterparties.  These derivative financial instruments do not qualify for hedge
accounting under SFAS 133. At March 31, 2003,  these  instruments had a net fair
market value of $0.06  million,  that was recorded on the  Consolidated  Balance
Sheet.  Based on the non-hedge  designation of these  instruments,  the gain was
recognized in the Consolidated Statement of Income.

Firm Gas Sales Derivative  Instruments - Regulated Utilities:  We use derivative
financial  instruments to reduce the cash flow  variability  associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution  operations.  Our strategy is to minimize  fluctuations in firm
gas sales prices to our regulated  firm gas sales  customers in our New York and
New  Hampshire  service  territories.  Since these  derivative  instruments  are
employed to reduce the  variability  of the purchase  price of natural gas to be
sold to regulated firm gas sales customers,  the accounting for these derivative
instruments is subject to SFAS 71  "Accounting  for the Effects of Certain Types
of Regulation". Therefore, changes in the market value of these derivatives have
been recorded as a Regulatory Asset or Regulatory  Liability on the Consolidated
Balance  Sheet.  Gains  or  losses  on the  settlement  of these  contracts  are
initially  deferred and then  refunded to or  collected  from our firm gas sales
customers consistent with regulatory requirements.

The following  table sets forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at March 31, 2003.
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                                 Year of      Volumes                                                      Fair Value
    Type of Contract             Maturity      mmcf       Fixed Price $         Current Price $              ($000)
---------------------------------------------------------------------------------------------------------------------
<S>                               <C>        <C>         <C>                    <C>                          <C>
Options                            2003        1,030      4.01 - 6.00            5.06 - 5.30                     (27)
                                   2004        2,140      5.00 - 6.00            4.54 - 5.38                    (793)
Swaps                              2003       10,470      4.01 - 5.84            5.06 - 5.30                  (2,682)
                                   2004        3,890      4.42 - 5.93            4.41 - 5.38                  (1,337)
---------------------------------------------------------------------------------------------------------------------
                                              17,530                                                          (4,839)
---------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       15
<PAGE>


Physically-Settled  Commodity Derivative Instruments:  Derivative Implementation
Group  ("DIG") Issue C15 and C16 of Statement of Financial  Accounting  Standard
133, "Accounting for Derivative Instruments and Hedging Activities",  as amended
and interpreted,  incorporating SFAS 137 and SFAS 138 and certain implementation
issues  (collectively "SFAS 133") establishes criteria that must be satisfied in
order for  option-type  and forward  contracts in  electricity to be exempted as
normal  purchases and sales,  and relates to the exemption (as normal  purchases
and normal sales) of contracts  that combine a forward  contract and a purchased
option  contract.  Based  upon a  continuing  review of our  physical  commodity
contracts,  we determined  that certain  contracts for the physical  purchase of
natural gas are not exempt as normal  purchases  from the  requirements  of SFAS
133. At March 31, 2003,  the fair value of these  contracts  was a negative $4.9
million.  Since  these  contracts  are for the  purchase  of natural gas sold to
regulated  firm gas sales  customers,  the  accounting  for these  contracts  is
subject to SFAS 71.  Therefore,  changes in the market value of these  contracts
have  been  recorded  as a  Regulatory  Asset  or  Regulatory  Liability  on the
Consolidated Balance Sheet.

Interest  Rate  Derivative  Instruments:  During 2002 we had interest  rate swap
agreements  in which  approximately  $1.3  billion  of fixed  rate debt had been
synthetically modified to floating rate debt. Under the terms of the agreements,
we  received  the fixed  coupon  rate  associated  with these bonds and paid the
counterparties  a variable  interest  rate that was reset on a quarterly  basis.
These swaps were  designated as fair-value  hedges and qualified for "short-cut"
hedge accounting treatment under SFAS 133.

In 2002,  we  terminated  two interest  rate swap  agreements  with an aggregate
notional amount of $1.0 billion. The remaining swap, which had a notional amount
of $270.0  million,  was  terminated  on February  25, 2003.  We received  $18.4
million from our swap counterparties as a result of the latter  termination,  of
which $8.1 million represented accrued swap interest. The difference between the
termination settlement amount and the amount of accrued interest, $10.3 million,
was  recorded to earnings  in the first  quarter of 2003.  This swap was used to
hedge a portion of our  outstanding  promissory  notes to LIPA.  As discussed in
Note 5 "Long-Term  Debt", we called a portion of these  promissory  notes during
the first quarter of 2003.

Additionally,  we had an interest rate swap  agreement that hedged the cash flow
variability  associated  with the forecasted  issuance of a series of commercial
paper offerings. This hedge expired in March 2003.



                                       16
<PAGE>


Weather  Derivatives:  The utility tariffs associated with KEDNE's operations do
not contain weather normalization  adjustments.  As a result,  fluctuations from
normal weather may have a significant positive or negative effect on the results
of these  operations.  To  mitigate  a  substantial  portion  of the  effect  of
fluctuations  from normal weather on our financial  position and cash flows,  we
sold  heating  degree-day  call  options and  purchased  heating-degree  day put
options for the November  2002-March  2003 winter  season.  With respect to sold
call  options,  KeySpan  was  required  to make a payment of $40,000 per heating
degree day to its  counterparties  when actual  weather  experienced  during the
November 2002 - March 2003 time frame was above 4,470 heating degree days, which
equates  to  approximately  1% colder  than  normal  weather.  With  respect  to
purchased put options,  KeySpan  would receive a $20,000 per heating  degree day
payment  from its  counterparties  when actual  weather was below 4,150  heating
degree days, or approximately 7% warmer than normal.  Based on the terms of such
contracts,  we account for such instruments pursuant to the requirements of EITF
99-2,  "Accounting for Weather Derivatives." In this regard, we account for such
instruments  using the  "intrinsic  value method" as set forth in such guidance.
During the first  quarter of 2003,  weather was 10% colder than normal and, as a
result, $11.9 million has been recorded as a reduction to revenues.

Derivative  contracts  are  primarily  used to manage  exposure  to market  risk
arising  from changes in commodity  prices and interest  rates.  In the event of
nonperformance  by a counterparty to a derivative  contract,  the desired impact
may not be  achieved.  The  risk of  counterparty  nonperformance  is  generally
considered  credit risk and is actively  managed by assessing each  counterparty
credit  profile and  negotiating  appropriate  levels of  collateral  and credit
support.

7. RECENT ACCOUNTING PRONOUNCEMENTS

In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143,
"Accounting for Asset  Retirement  Obligations."  SFAS 143 requires an entity to
record a liability and  corresponding  asset  representing  the present value of
legal obligations associated with the retirement of tangible, long-lived assets.
SFAS 143 was effective for fiscal years beginning after June 2002.

At March 31, 2003, the present value of our future Asset  Retirement  Obligation
("ARO") was  approximately  $57 million,  primarily related to our investment in
Houston  Exploration.  The  cumulative  effect  of SFAS  143 and the  change  in
accounting  principle  was a  benefit  to net  income of $0.6  million,  or $0.2
million,  after-tax.  KeySpan's  largest asset base is its gas  transmission and
distribution   system.  A  legal   obligation   exists  due  to  certain  safety
requirements  at final  abandonment.  In  addition,  a legal  obligation  may be
construed  to exist with  respect to  KeySpan's  liquefied  natural  gas ("LNG")
storage tanks due to clean up  responsibilities  upon cessation of use. However,
mass assets such as storage,  transmission and distribution  assets are believed
to operate in perpetuity and, therefore, have indeterminate cash flow estimates.
Since that exposure is in perpetuity  and cannot be measured,  no liability will
be  recorded.  KeySpan's  ARO  will be  re-evaluated  in  future  periods  until
sufficient information exists to determine a reasonable estimate of fair value.


                                       17
<PAGE>


KeySpan  recovers  certain  asset  retirement  costs  through  rates  charged to
customers as a portion of depreciation expense. When depreciable  properties are
retired,  the  original  cost plus cost of removal less  salvage,  is charged to
accumulated  depreciation.  As of March 31, 2003, KeySpan had costs recovered in
excess of costs incurred totaling $422.5 million.

In  January  2003,  the  FASB  issued  FASB  Interpretation  No.  46  "FIN  46",
"Consolidation of Variable Interest Entities,  an Interpretation of ARB No. 51."
FIN 46 requires  certain  variable  interest  entities to be consolidated by the
primary  beneficiary of the entity if the equity  investors in the entity do not
have the  characteristics  of a  controlling  financial  interest or do not have
sufficient  equity at risk for the  entity to  finance  its  activities  without
additional  subordinated  financial  support  from  other  parties.  FIN  46  is
effective  for all new  variable  interest  entities  created or acquired  after
January 31, 2003. For variable  interest  entities  created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period beginning after June 15, 2003. We currently have an arrangement
with a  variable  interest  entity  through  which  we  lease a  portion  of the
Ravenswood facility and we will apply the provisions of FIN 46 beginning July 1,
2003. (See Note 9 "Variable Interest Entity" for a detailed  description of this
leasing arrangement).

8. FINANCIAL GUARANTEES AND CONTINGENCIES

Environmental Matters


New York Sites. We have  identified 28 manufactured  gas plant ("MGP") sites and
related facilities in New York State that were historically owned or operated by
KeySpan  subsidiaries  or such  companies'  predecessors.  Twenty seven of these
former sites, some of which are no longer owned by KeySpan, were associated with
the regulated gas businesses, and have been identified to both the Department of
Environmental Conservation ("DEC") for inclusion on appropriate site inventories
and listing with the New York Public Service Commission ("NYPSC"). The remaining
former MGP site was acquired when the  Ravenswood  facility was  purchased  from
Consolidated Edison Company of New York Inc. ("Consolidated  Edison").  Fourteen
sites are currently the subjects of Administrative Orders on Consent ("ACOs") or
Voluntary Clean-Up Agreements ("VCAs") with the DEC.

We presently estimate the remaining  environmental  cleanup costs related to our
New York MGP sites will be $137.9  million,  which  amount has been accrued as a
reasonable estimate of probable cost for known sites.  Expenditures  incurred to
date with respect to these MGP-related sites total $53.5 million.  The KEDNY and
KEDLI rate plans generally provide for the recovery of MGP related investigation
and  remediation  costs in rates charged to gas  distribution  customers.  Under
prior rate orders,  KEDNY has offset certain  refunds due customers  against its
estimated  environmental  cleanup  costs for MGP sites.  A  regulatory  asset of
$121.6 million for the New York/Long  Island MGP sites is reflected at March 31,
2003.



                                       18
<PAGE>

KeySpan is also responsible for  environmental  obligations  associated with the
Ravenswood  electric generating  facility.  Our obligations do not include those
arising from disposal of waste at off-site locations prior to our acquisition of
the Ravenswood facility,  or any from Consolidated Edison's post-closing conduct
associated with its  transmission  facilities at the site.  Based on information
currently available, a liability of $3.6 million has been accrued.  Expenditures
incurred  to date with  respect to these  environmental  obligations  total $1.4
million.

New England Sites. Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 76 former MGP sites and related facilities within the
existing or former service territories of KEDNE.

Boston Gas Company, Colonial Gas Company and Essex Gas Company may have or share
responsibility under applicable environmental laws for the remediation of 66 MGP
sites and related  facilities.  A  subsidiary  of National  Grid USA  ("National
Grid"),  formerly New England Electric System,  has assumed  responsibility  for
remediating 11 of these sites, subject to a limited contribution from Boston Gas
Company,  and has  provided  full  indemnification  to Boston Gas  Company  with
respect to eight other sites. At this time, there is substantial  uncertainty as
to whether Boston Gas Company, Colonial Gas Company or Essex Gas Company have or
share  responsibility  for  remediating  any of these other sites.  No notice of
responsibility  has  been  issued  to  us  for  any  of  these  sites  from  any
governmental environmental authority.

We  presently   estimate  the   remaining   cost  of  New  England   MGP-related
environmental  cleanup  activities will be $46.9 million,  which amount has been
accrued as a reasonable estimate of probable cost for known sites.  Expenditures
incurred since our  acquisition of Eastern  Enterprises on November 8, 2000 with
respect to these MGP-related activities total $16.7 million.

The Massachusetts  Department of  Telecommunications  and Energy ("DTE") and the
New Hampshire Public Utilities Commission ("NHPUC") have issued rate orders that
provide for the recovery of site  investigation  and remediation  costs in rates
charged to gas distribution customers.  Accordingly, a regulatory asset of $58.4
million for the KEDNE MGP sites is  reflected  at March 31,  2003.  Colonial Gas
Company and Essex Gas Company are not subject to the  provisions of Statement of
Financial  Accounting  Standards  ("SFAS")  71  "Accounting  for the  Effects of
Certain Types of Regulation"  and therefore  have recorded no regulatory  asset.
However, rate plans in effect for these subsidiaries provide for the recovery of
investigation and remediation costs.

KeySpan  New  England  LLC  Sites.  We are  aware  of  three  non-utility  sites
associated  with the  historical  operations  of KeySpan New  England,  LLC, the
successor  company  to  Eastern  Enterprises,  for  which  we may  have or share
environmental  remediation  responsibility  or ongoing  maintenance:  the former
Philadelphia Coke site located in Pennsylvania; the former Connecticut Coke site
located in New Haven,  Connecticut;  and the Everett  site,  which  includes the


                                       19
<PAGE>

former Coal Tar  Processing  Facility (the "Everett  Coal Tar  Facility"),  Coke
Plant  and  a  by-products   facility   located  in   Massachusetts.   Honeywell
International,  Inc. and Beazer East,  Inc.  (both former owners or operators of
the Everett Coal Tar  Facility)  together  with KeySpan have entered into an ACO
with  the   Massachusetts   Department  of  Environmental   Protection  for  the
investigation  and development of a remedial  response plan for the Everett Coal
Tar Facility.

We presently estimate the remaining cost of our environmental cleanup activities
for the three  non-utility  sites will be  approximately  $38.8  million,  which
amount has been  accrued as a  reasonable  estimate of probable  costs for known
sites. Expenditures incurred since November 8, 2000, with respect to these sites
total $4.5 million.

We believe that in the aggregate,  the accrued  liability for  investigation and
remediation  of sites and related  facilities  identified  above are  reasonable
estimates of likely cost within a range of reasonable, foreseeable costs. We may
be required to investigate and, if necessary,  remediate each of these, or other
currently  unknown former sites and related facility sites, the cost of which is
not  presently  determinable  but may be  material  to our  financial  position,
results  of  operations  or  liquidity.  Remediation  costs for each site may be
materially higher than noted,  depending upon remediation  experience,  selected
end use for each site, and actual environmental conditions encountered.

See  KeySpan's  Annual  Report on Form 10K for the year ended  December 31, 2002
Note 7 to those Consolidated Financial Statements  "Contractual  Obligations and
Contingencies" for further information on environmental matters.

Legal Matters

From time to time we are subject to various legal proceedings arising out of the
ordinary  course of our  business.  Except as described  below,  or in KeySpan's
Annual  Report  on Form 10K for the year  ended  December  31,  2002,  we do not
consider  any of such  proceedings  to be material to our  business or likely to
result in a material  adverse  effect on our  results of  operations,  financial
condition or cash flows.

KeySpan has been  cooperating  in  preliminary  inquiries  regarding  trading in
KeySpan  Corporation  stock by individual  officers of KeySpan prior to the July
17, 2001  announcement  that  KeySpan was taking a special  charge in its Energy
Services  business and  otherwise  reducing its 2001  earnings  forecast.  These
inquiries are being conducted by the U.S.  Attorney's Office,  Southern District
of New York and the SEC.

As previously reported, as part of its continuing inquiry, on March 5, 2002, the
SEC issued a formal order of investigation, pursuant to which it will review the
trading activity of certain company insiders from May 1, 2001 to the present, as
well as KeySpan's compliance with its reporting rules and regulations, generally
during the period following the acquisition by KeySpan Services, Inc., a KeySpan
subsidiary, of the Roy Kay companies through the July 17th announcement.


                                       20
<PAGE>


KeySpan and certain of its officers and directors are  defendants in a number of
class action  lawsuits filed in the United States District Court for the Eastern
District of New York after the July 17th  announcement.  These lawsuits  allege,
among other  things,  violations of Sections  10(b) and 20(a) of the  Securities
Exchange  Act  of  1934,  as  amended   ("Exchange  Act"),  in  connection  with
disclosures  relating to or following the  acquisition  of the Roy Kay companies
and the announcement of the agreement to acquire Eastern  Enterprises and Energy
North Inc.. In October 2001, a shareholder's  derivative action was commenced in
the same court  against  certain  officers and  directors of KeySpan,  alleging,
among other  things,  breaches of  fiduciary  duty,  violations  of the New York
Business Corporation Law and violations of Section 20(a) of the Exchange Act. In
addition,  a second  derivative  action  has been  commenced  asserting  similar
allegations.  Each of the  proceedings  seek monetary  damages in an unspecified
amount.  On March 18,  2003 the court  granted  our motion to dismiss  the class
action  complaint.  The court's order dismissed  certain class  allegations with
prejudice,  but provided the  plaintiffs a final  opportunity to file an amended
complaint  concerning  the remaining  allegations.  In April 2003, the plaintiff
filed an  amended  complaint  and we  intend  to file a motion  to  dismiss  the
complaint.  We are unable to predict the outcome of these proceedings or effect,
if any, such outcome will have on our financial condition, results of operations
or cash flows.

KeySpan  subsidiaries,  along with  several  other  parties,  have been named as
defendants in numerous  proceedings filed by plaintiffs claiming various degrees
of injury from asbestos exposure at generating facilities formerly owned by Long
Island Lighting Company and others.  In March 2003, a jury rendered a verdict in
one such  proceeding  against our subsidiary,  KeySpan  Generation LLC ("KeySpan
Generation"),  and other  defendants  in the amount of $47 million.  KeySpan has
moved to set aside this verdict and, if necessary,  will prosecute an appeal, on
the grounds that, among other things, the amount of the verdict is excessive and
unreasonable  and the finding of liability  against  KeySpan  Generation  is not
supported by the evidence.

In connection with the May 1998 transaction with the Long Island Power Authority
("LIPA"),  costs  incurred  by KeySpan for  liabilities  for  asbestos  exposure
arising from the activities of the generating facilities previously owned by the
Long  Island  Lighting  Company,  including  the  facility  involved in the case
referred to above,  are recoverable from LIPA through the Power Supply Agreement
between  LIPA and  KeySpan.  KeySpan's  cost  recovery  under the  Power  Supply
Agreement is reduced by any insurance  recoveries received by KeySpan Generation
and by amounts received by KeySpan Generation from other indemnification  claims
it is pursuing.

KeySpan  is  unable  to  determine  the  outcome  of the  appeals  of the  above
referenced action or the outcome of any of these other proceedings, but does not
believe,  for the reasons set forth above, that such outcome,  if adverse,  will
have a material  effect on its  financial  condition  or  results of  operation.
KeySpan believes that its cost recovery rights under the Power Supply Agreement,
its  indemnification  rights  against third  parties and its insurance  coverage
(above  applicable  deductible  limits)  cover its exposure in this case and for
asbestos liabilities generally.

Financial Guarantees

KeySpan  has  issued  financial  guarantees  in the normal  course of  business,
primarily on behalf of its  subsidiaries,  to various third party creditors.  At
March 31, 2003,  the  following  amounts would have to be paid by KeySpan in the
event of non-payment by the primary obligor at the time payment is due:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
                                                                                Amount of     Expiration
Nature of Guarantee (In Thousands of Dollars)                                    Exposure        Dates
------------------------------------------------------------------------------------------------------------
Guarantees for Subsidiaries
<S>                                                             <C>             <C>           <C>
Medium-Term Notes - KEDLI                                       (i)            $   525,000     2008-2010
Master Lease  - Ravenswood                                      (ii)               425,000       2004
Revolving Credit Agreement - KeySpan Canada                     (iii)              130,000       2004
Surety Bonds                                                    (iv)               150,080     Revolving
Commodity Guarantees and Other                                  (v)                 99,967       2005
Letters of Credit                                               (vi)                64,822       2003
------------------------------------------------------------------------------------------------------------
Guarantees for Non-Affiliates
Third Party Line of Credit                                      (vii)               25,000       2004
Surety Bonds                                                    (vii)                8,725     Revolving
------------------------------------------------------------------------------------------------------------
                                                                               $ 1,428,594
------------------------------------------------------------------------------------------------------------
</TABLE>

                                       21
<PAGE>


The following is a description of KeySpan's outstanding subsidiary guarantees:

(i)  KeySpan has fully and unconditionally guaranteed $525 million to holders of
     Medium-Term  Notes  issued  by KEDLI.  These  notes are due to be repaid on
     January  15, 2008 and  February  1, 2010.  KEDLI is required to comply with
     certain financial covenants under the debt agreements.  Currently, KEDLI is
     in compliance  with all covenants and management  does not anticipate  that
     KEDLI will have any difficulty maintaining such compliance.  The face value
     of these notes is included in Long-Term  Debt on the  Consolidated  Balance
     Sheet.

(ii) KeySpan has guaranteed all payment and  performance  obligations of KeySpan
     Ravenswood,  LLC, the lessee under the $425 million Ravenswood Master Lease
     (the "Master Lease") associated with the lease of the Ravenswood  facility.
     The initial term of the lease  expires on June 20, 2004 and may be extended
     until June 20, 2009. For further information, see Note 9 "Variable Interest
     Entity."

(iii)KeySpan  has  fully  and  unconditionally  guaranteed  a  US  $130  million
     revolving credit agreement  associated with KeySpan Canada. The term of the
     agreement expires January 1, 2004.

(iv) KeySpan  has  agreed  to  indemnify  the  issuers  of  various  surety  and
     performance bonds associated with certain  construction  projects currently
     being performed by subsidiaries  within the Energy Services segment. In the
     event that the operating  companies in the Energy Services  segment fail to
     perform their obligations under contract, the injured party may demand that
     the surety make payments or provide services under the bond.  KeySpan would
     then be obligated to reimburse  the surety for any expenses or cash outlays
     it incurs.

(v)  KeySpan has guaranteed  commodity-related  payments for subsidiaries within
     the Energy  Services  segment,  as well as KeySpan  Ravenswood,  LLC. These
     guarantees  are  provided  to third  parties  to  facilitate  physical  and
     financial  transactions  involved in the  purchase of natural  gas, oil and
     other petroleum products for electric production and marketing  activities.
     The guarantees cover actual purchases by these  subsidiaries that are still
     outstanding as of March 31, 2003.

(vi) KeySpan has arranged for stand-by  letters of credit in the amount of $64.8
     million to be issued to third parties that have extended  credit to certain
     subsidiaries.  Certain  vendors  require  us to post  letters  of credit to
     guarantee subsidiary  performance under our contracts and to ensure payment
     to our subsidiary subcontractors and vendors under those contracts. Certain
     of our vendors also require letters of credit to ensure  reimbursement  for
     amounts  they are  disbursing  on  behalf of our  subsidiaries,  such as to
     beneficiaries  under our self-funded  insurance  programs.  Such letters of
     credit are generally issued by a bank or similar financial institution. The
     letters of credit commit the issuer to pay specified  amounts to the holder
     of the letter of credit if the holder  demonstrates  that we have failed to
     perform specified actions. If this were to occur, KeySpan would be required
     to reimburse the issuer of the letter of credit.


                                       22
<PAGE>


To  date,  KeySpan  has not had a claim  made  against  it for any of the  above
guarantees and we have no reason to believe that our  subsidiaries  will default
on their current obligations. However, we cannot predict when or if any defaults
may take place or the impact such defaults may have on our consolidated  results
of operations, financial condition or cash flows.

The  following  is  a  description  of  KeySpan's   outstanding   guarantees  to
non-affiliates:

(vii)KeySpan  has agreed to support a line of credit up to $25 million on behalf
     of Hawkeye  Construction  ("Hawkeye"),  a non-affiliated  company.  It also
     assisted Hawkeye in obtaining  performance bonds. The guarantees related to
     their line of credit extend  through  2004. To the extent  Hawkeye does not
     meet  its  obligations,  KeySpan  could be  liable  for the  amount  of the
     outstanding  guarantees.  At March 31, 2003, the amount  guaranteed was $25
     million.

     If Hawkeye fails to perform under a contract or to pay  subcontractors  and
     vendors,  the  counterparty  that requested the performance bond may demand
     that the surety make payments or provide  services under the bond.  KeySpan
     would then have to  reimburse  the surety for any  expenses  or outlays the
     surety  incurs.  To date,  we have not had a claim made against  either the
     guarantee  associated  with the line of  credit or the  performance  bonds.
     KeySpan is presently engaged in a legal action with Hawkeye. (See KeySpan's
     Annual  Report  on form 10K for the year  ended  December  31,  2002 Note 7
     "Contractual  Obligations,  Financial  Guarantees  and  Contingencies"  for
     further information on this legal proceeding.)

9. VARIABLE INTEREST ENTITY

KeySpan has an  arrangement  with a variable  interest  entity  through which we
lease a portion of the Ravenswood facility. We acquired the Ravenswood facility,
in part,  through the variable interest entity from Consolidated  Edison on June
18, 1999 for  approximately  $597  million.  In order to reduce the initial cash
requirements,  we  entered  into the  Master  Lease  with a  variable  interest,
unaffiliated  financing  entity that acquired a portion of the  facility,  three
steam generating units,  directly from Consolidated  Edison and leased it to our
subsidiary.  The variable  interest  unaffiliated  financing entity acquired the
property  for  $425  million,  financed  with  debt of  $412.3  million  (97% of
capitalization) and equity of $12.7 million (3% of capitalization).  KeySpan has
no ownership interests in the steam units or in the variable interest entity.

KeySpan has guaranteed all payment and performance obligations of our subsidiary
under the Master Lease. The Master Lease represents  approximately  $425 million
of the acquisition cost of the facility,  which is the amount of debt that would
have been recorded on our Consolidated  Balance Sheet had the variable  interest
entity not been utilized and conventional debt financing been employed. Further,
we would have recorded an asset in the same amount. Monthly lease payments equal
the monthly interest expense on such debt securities. The Master Lease currently
qualifies as an operating lease for financial reporting purposes.


                                       23
<PAGE>


The  initial  term of the  Master  Lease  expires  on June  20,  2004 and may be
extended  until June 20,  2009.  In June 2004,  we have the right to: (i) either
purchase the facility for the original  acquisition  cost of $425 million,  plus
the present  value of the lease  payments  that would  otherwise  have been paid
through June 2009;  (ii) terminate the Master Lease and dispose of the facility;
or (iii)  otherwise  extend the  Master  Lease to 2009.  If the Master  Lease is
terminated in 2004, KeySpan has guaranteed an amount  approximately equal to 83%
of the residual  value of the original  cost of the  property,  plus the present
value of the lease payments that would have otherwise been paid through June 20,
2009.  In June 2009,  when the Master  Lease  terminates,  we may  purchase  the
facility  in an  amount  equal to the  original  acquisition  cost,  subject  to
adjustment, or surrender the facility to the lessor. If we elect not to purchase
the  property,  the  Ravenswood  facility  will be sold by the  lessor.  We have
guaranteed  to the lessor 84% of the residual  value of the original cost of the
property.

In January 2003,  the FASB issued FIN 46,  "Consolidation  of Variable  Interest
Entities, an Interpretation of ARB No. 51." FIN 46 requires KeySpan,  based upon
its current  status as the primary  beneficiary,  to  consolidate  this variable
interest entity for the first interim period ending after June 15, 2003. It also
requires that assets,  liabilities and non-controlling interests of the variable
interest entity be  consolidated at fair value,  except to the extent that to do
so would  result in a gain to  KeySpan.  KeySpan  believes  that the fair market
value of the  Ravenswood  facility  exceeds the fair  market  value of the lease
obligation.

Prospectively,  KeySpan  will have a $425  million  asset that will be amortized
over the economic life of the leased  property.  However,  upon  implementation,
there will be a cumulative catch-up adjustment for a change in accounting policy
as if the asset had been owned from inception,  or June 20, 1999. Therefore,  at
July 1, 2003,  assuming a 35 year economic life,  KeySpan will be deemed to have
owned the asset for  approximately  4 years and it is  anticipated  that we will
record  a $29.1  million  after-tax  charge,  or  $0.18  per  share,  change  in
accounting   principle   on  the   Consolidated   Statement   of  Income.   Upon
implementation  of FIN 46,  therefore,  we  anticipate  recording  an  asset  of
approximately $376 million and debt of $425 million.

Based upon expected average  outstanding  shares,  we anticipate the incremental
impact of the  additional  depreciation  expense for the remaining six months of
2003  to be  approximately  $0.02  per  share.  In  addition,  KeySpan  is  also
conducting  a study to  determine  the fair  value of the  Ravenswood  facility.
Although  considered  unlikely,  to the extent the fair value of the  Ravenswood
facility was less than the value of the lease  obligation,  then a loss would be
recognized upon consolidation.

If our subsidiary  that leases the  Ravenswood  facility was not able to fulfill
its payment  obligations  with  respect to the Master Lease  payments,  then the
maximum amount KeySpan would be exposed to under its current guarantees would be
$425 million plus the present value of the remaining lease payments through June
20, 2009.


                                       24
<PAGE>


10. STOCK OPTIONS

Stock options have been issued to KeySpan officers,  directors and certain other
management  employees  and  consultants  as approved by the Board of  Directors.
These  options  generally  vest  over a  three-to-five  year  period  and have a
ten-year exercise period.  Moreover,  under a separate plan, Houston Exploration
has issued stock options to its directors and key Houston Exploration employees.
During  2002,   we  announced  our  intention  to  record  stock  options  as  a
compensation  expense  beginning  with those  options  granted in 2003. In 2003,
KeySpan and Houston  Exploration adopted the prospective method of transition in
accordance with SFAS 148  "Accounting for Stock-Based  Compensation - Transition
and  Disclosure".  Accordingly,  compensation  expense  has been  recognized  by
employing  the fair value  recognition  provisions of SFAS 123  "Accounting  for
Stock-Based Compensation" for grants awarded after January 1, 2003.

KeySpan and Houston  Exploration  continue to apply APB Opinion 25,  "Accounting
for Stock Issued to Employees,"  and related  Interpretations  in accounting for
grants awarded prior to January 1, 2003.  Accordingly,  no compensation cost has
been recognized for these fixed stock option plans in the Consolidated Financial
Statements  since the exercise  prices and market values were equal on the grant
dates. Had  compensation  cost for these plans been determined based on the fair
value at the grant dates for awards  under the plans  consistent  with SFAS 123,
our net income and  earnings  per share would have  decreased  to the  pro-forma
amounts indicated below:
<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------------------------------------
                                                                                              Three Months Ended March 31,
(In Thousands of Dollars, Except Per Share Amounts)                                          2003                     2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>                     <C>
Earnings available for common stock:
As reported                                                                                $ 241,804               $ 213,155
     Add: recorded stock-based compensation expense, net of tax                                  857                       -
     Deduct: total stock-based compensation expense, net of tax                               (2,913)                 (1,831)
------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings                                                                         $ 239,748               $ 211,324
------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
     Basic - as reported                                                                      $ 1.54                  $ 1.52
     Basic - pro-forma                                                                        $ 1.53                  $ 1.51

     Diluted - as reported                                                                    $ 1.53                  $ 1.51
     Diluted - pro-forma                                                                      $ 1.52                  $ 1.50
------------------------------------------------------------------------------------------------------------------------------
</TABLE>


11. SUBSEQUENT EVENTS

Boston Gas Company's gas rates for local distribution service were governed by a
five-year   performance-based   rate  plan   approved  by  the   Department   of
Telecommunications  and Energy  ("DTE") in 1996 (the  "Plan"),  that  expired in
October 2002.  Boston Gas Company filed a base rate case and  performance  based
rate plan on April 16, 2003, to be effective in the fourth  quarter of 2003. The
filing requests an annual revenue  increase of  approximately  $61 million and a
performance based rate plan term of five years.


                                       25
<PAGE>

In its order approving the acquisition by KeySpan of Eastern  Enterprises  Inc.,
the SEC  reserved  jurisdiction  on its  determination  of  whether  the  Energy
Services  companies were retainable  under existing PUHCA rule or precedent.  On
April 24,  2003,  the SEC issued an order  authorizing  the  retention  of these
companies.

On May 1, 2003, KeySpan's gas and electric marketing subsidiary,  KeySpan Energy
Services,  assigned a substantial  portion of its retail  natural gas customers,
consisting  mostly of residential and small commercial  customers,  to ECONnergy
Energy Co.,  Inc.  ("ECONnergy").  ECONnergy  is one of the largest  deregulated
energy service companies in the Northeast. KeySpan Energy Services will continue
to provided  retail  natural gas marketing to a small number of customers in New
Jersey and will continue its electric marketing activities.

12. KEYSPAN GAS EAST CORPORATION SUMMARY FINANCIAL INFORMATION

KEDLI is a wholly owned  subsidiary of KeySpan.  KEDLI was formed on May 7, 1998
and on May 28, 1998 acquired  substantially all of the assets related to the gas
distribution  business of LILCO.  KEDLI  established a program for the issuance,
from  time  to  time,  of up to  $600  million  aggregate  principal  amount  of
Medium-Term Notes, which are fully and unconditionally guaranteed by the parent,
KeySpan  Corporation.  On February 1, 2000,  KEDLI issued $400 million of 7.875%
Medium-Term  Notes due 2010.  In January 2001,  KEDLI issued an additional  $125
million of Medium-Term  Notes at 6.9% due January 2008. The following  condensed
financial  statements  are required to be disclosed by SEC  regulations  and set
forth those of KEDLI,  KeySpan Corporation as guarantor of the Medium-Term Notes
and our other  subsidiaries on a combined basis.  The March 31, 2002 disclosures
have been revised to separately present our other subsidiaries.
<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------------------------------------------
                           Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                         Three Months Ended March 31, 2003
(In Thousands of Dollars)                           Guarantor         KEDLI      Other Subsidiaries     Eliminations    Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>             <C>             <C>                 <C>             <C>
Revenues                                            $     143        $478,345        $2,034,180        $     (143)      $ 2,512,525
Operating Expenses
  Purchased gas                                             -         287,009           909,156                 -         1,196,165
  Fuel and purchased power                                  -               -            97,522                 -            97,522
  Operations and maintenance                            7,259          38,220           452,710                 -           498,189
  Intercompany expense                                     34           1,182            (1,182)              (34)                -
  Depreciation and amortization                           (20)         26,920           118,071                 -           144,971
  Operating taxes                                           -          24,005           100,708                 -           124,713
                                                ------------------------------------------------------------------------------------
Total Operating Expenses                                7,273         377,336         1,676,985               (34)        2,061,560

                                                ------------------------------------------------------------------------------------
Operating Income (Loss)                                (7,130)        101,009           357,195              (109)          450,965

Interest charges                                      (46,477)        (15,006)          (52,299)           44,843           (68,939)
Other income and (deductions)                         293,453          (7,217)           10,243          (292,581)            3,898
                                                ------------------------------------------------------------------------------------
Total Other Income and (Deductions)                   246,976         (22,223)          (42,056)         (247,738)          (65,041)

Income (Loss) Before Income Taxes                     239,846          78,786           315,139          (247,847)          385,924

Income Taxes                                           (3,419)         28,312           117,940                 -           142,833
                                                ------------------------------------------------------------------------------------
Earnings before Change in Accounting Principle      $ 243,265        $ 50,474        $  197,199        $ (247,847)      $   243,091

Cumulative Effect of Change in Accouting
    Principle                                               -               -               174                 -               174
                                                ------------------------------------------------------------------------------------
Net Income                                          $ 243,265        $ 50,474        $  197,373        $ (247,847)      $   243,265
                                                ====================================================================================
</TABLE>

                                       26
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                           Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                    Three Months Ended March 31, 2002
(In Thousands of Dollars)                         Guarantor         KEDLI       Other Subsidiaries      Eliminations    Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                <C>             <C>               <C>                <C>              <C>
Revenues                                          $     104       $ 318,947         $ 1,554,631        $     (104)      $ 1,873,578
Operating Expenses
  Purchased gas                                           -         142,867             506,493                 -           649,360
  Fuel and purchased power                                -               -              84,372                 -            84,372
  Operations and maintenance                          1,506          12,001             484,568                 -           498,075
  Intercompany expense                                   56          18,209             (18,209)              (56)                -
  Depreciation and amortization                           -          20,241             105,756                 -           125,997
  Operating taxes                                       570          25,386              87,946                 -           113,902
                                              --------------------------------------------------------------------------------------
Total Operating Expenses                              2,132         218,704           1,250,926               (56)        1,471,706

                                              --------------------------------------------------------------------------------------
Operating Income (Loss)                              (2,028)        100,243             303,705               (48)          401,872

Interest charges                                    (46,929)        (15,202)            (67,772)           57,291           (72,612)
Other income and (deductions)                       263,251           2,902              17,056          (272,529)           10,680
                                              --------------------------------------------------------------------------------------
Total Other Income and (Deductions)                 216,322         (12,300)            (50,716)         (215,238)          (61,932)

Income (Loss) Before Income Taxes                   214,294          87,943             252,989          (215,286)          339,940

Income Taxes                                           (337)         37,081              88,565                 -           125,309

                                              --------------------------------------------------------------------------------------
Net Income                                        $ 214,631       $  50,862         $   164,424        $ (215,286)      $   214,631
                                              ======================================================================================
</TABLE>









                                       27
<PAGE>

<TABLE>
<CAPTION>

-----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                    March 31, 2003
                                                    Guarantor          KEDLI      Other Subsidiaries   Eliminations    Consolidated
                                             --------------------------------------------------------------------------------------
<S>                                                <C>             <C>                <C>             <C>              <C>
ASSETS
Current Assets
   Cash & temporary cash investments              $    90,558     $    14,285        $    139,219    $          -     $    244,062
   Accounts receivable, net                             8,206         331,104           1,712,805               -        2,052,115
   Other current assets                                 1,550          13,048             257,578               -          272,176
                                             --------------------------------------------------------------------------------------
                                                      100,314         358,437           2,109,602               -        2,568,353
                                             --------------------------------------------------------------------------------------

Investments and Other                               3,922,991           2,629             207,382      (3,864,124)         268,878
                                             --------------------------------------------------------------------------------------
Property
   Gas                                                      -       1,796,884           4,405,849               -        6,202,733
   Other                                                    -               -           4,991,336               -        4,991,336
   Accumulated depreciation and depletion                   -        (330,384)         (3,487,881)              -       (3,818,265)
                                             --------------------------------------------------------------------------------------
                                                            -       1,466,500           5,909,304               -        7,375,804
                                             --------------------------------------------------------------------------------------

Intercompany Accounts Receivable                    3,683,508          13,637             634,910      (4,332,055)               -

Deferred Charges                                      323,858         187,739           2,406,174               -        2,917,771

                                             --------------------------------------------------------------------------------------
Total Assets                                      $ 8,030,671     $ 2,028,942        $ 11,267,372    $ (8,196,179)    $ 13,130,806
                                             ======================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                               $    74,724     $   121,056        $  1,016,626    $          -     $  1,212,406
   Commercial paper                                   677,332               -                   -               -          677,332
   Other current liabilities                          325,258         163,662             (27,361)              -          461,559
                                             --------------------------------------------------------------------------------------
                                                    1,077,314         284,718             989,265               -        2,351,297
                                             --------------------------------------------------------------------------------------
Intercompany Accounts Payable                               -         105,215           2,095,456      (2,200,671)               -
                                             --------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                                   (45,924)        142,933             790,699               -          887,708
Other deferred credits and liabilities                509,695          97,609             538,541               -        1,145,845
                                             --------------------------------------------------------------------------------------
                                                      463,771         240,542           1,329,240               -        2,033,553
                                             --------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                         3,655,742         697,563           3,123,968      (3,864,124)       3,613,149
Preferred stock                                        83,849               -                   -               -           83,849
Long-term debt                                      2,749,995         700,904           3,420,716      (2,131,384)       4,740,231
                                             --------------------------------------------------------------------------------------
Total Capitalization                                6,489,586       1,398,467           6,544,684      (5,995,508)       8,437,229
                                             --------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies                   -               -             308,727               -          308,727
                                             --------------------------------------------------------------------------------------
Total Liabilities & Capitalization                $ 8,030,671     $ 2,028,942        $ 11,267,372    $ (8,196,179)    $ 13,130,806
                                             ======================================================================================
</TABLE>



                                       28
<PAGE>

<TABLE>
<CAPTION>

-----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                 December 31, 2002
                                                  Guarantor          KEDLI      Other Subsidiaries     Eliminations    Consolidated
                                           ----------------------------------------------------------------------------------------
<S>                                               <C>             <C>               <C>               <C>              <C>
ASSETS
Current Assets
   Cash & temporary cash investments            $    88,308     $     6,472       $     75,837       $          -     $    170,617
   Accounts receivable, net                          23,982         208,512          1,299,559                  -        1,532,053
   Other current assets                               1,757          79,206            423,596                  -          504,559
                                           ----------------------------------------------------------------------------------------
                                                    114,047         294,190          1,798,992                  -        2,207,229
                                           ----------------------------------------------------------------------------------------

Investments and Other                             3,797,964           2,717            201,675         (3,736,379)         265,977
                                           ----------------------------------------------------------------------------------------
Property
   Gas                                                    -       1,771,780          4,352,501                  -        6,124,281
   Other                                                  -               -          4,807,724                  -        4,807,724
   Accumulated depreciation and depletion                 -        (322,236)        (3,392,169)                 -       (3,714,405)
                                           ----------------------------------------------------------------------------------------
                                                          -       1,449,544          5,768,056                  -        7,217,600
                                           ----------------------------------------------------------------------------------------

Intercompany Accounts Receivable                  3,619,515          54,549            822,725         (4,496,789)               -

Deferred Charges                                    339,443         192,652          2,391,405                  -        2,923,500

                                           ----------------------------------------------------------------------------------------
Total Assets                                    $ 7,870,969     $ 1,993,652       $ 10,982,853       $ (8,233,168)    $ 12,614,306
                                           ========================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                             $   132,966     $    68,772       $    859,911       $          -     $  1,061,649
   Commercial paper                                 915,697               -                  -                  -          915,697
   Other current liabilities                        107,605         104,975             30,302                  -          242,882
                                           ----------------------------------------------------------------------------------------
                                                  1,156,268         173,747            890,213                  -        2,220,228
                                           ----------------------------------------------------------------------------------------
Intercompany Accounts Payable                             -         233,392          2,182,013         (2,415,405)               -
                                           ----------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                                 (43,110)        139,715            780,408                  -          877,013
Other deferred credits and liabilities              481,964          98,805            453,353                  -        1,034,122
                                           ----------------------------------------------------------------------------------------
                                                    438,854         238,520          1,233,761                  -        1,911,135
                                           ----------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                       2,983,214         647,089          3,050,668         (3,736,379)       2,944,592
Preferred stock                                      83,849               -                  -                  -           83,849
Long-term debt                                    3,208,784         700,904          3,395,777         (2,081,384)       5,224,081
                                           ----------------------------------------------------------------------------------------
Total Capitalization                              6,275,847       1,347,993          6,446,445         (5,817,763)       8,252,522
                                           ----------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies                 -               -            230,421                  -          230,421
                                           ----------------------------------------------------------------------------------------
Total Liabilities & Capitalization              $ 7,870,969     $ 1,993,652       $ 10,982,853       $ (8,233,168)    $ 12,614,306
                                           ========================================================================================
</TABLE>




                                       29
<PAGE>


<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
-------------------------------------------------------------------------------------------------------------------------------
                                                                              Three Months Ended March 31, 2003
                                                       ------------------------------------------------------------------------
                                                             Guarantor         KEDLI         Other Subsidiaries    Consolidated
                                                       ------------------------------------------------------------------------
<S>                                                         <C>              <C>                   <C>               <C>
Operating Activities
Net Cash Provided by Operating Activities                   $ 239,598       $ 121,019              $ 129,272         $ 489,889
                                                       ------------------------------------------------------------------------
Investing Activities
   Capital expenditures                                             -         (25,941)              (194,838)         (220,779)
   Proceeds from Monetization of Houston Exploration           79,200               -                      -            79,200
                                                       ------------------------------------------------------------------------
Net Cash Provided by (Used in) Investing Activities            79,200         (25,941)              (194,838)         (141,579)
                                                       ------------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                       26,307               -                      -            26,307
   Equity Issuance                                            473,573               -                      -           473,573
   Redemption of Promissory Notes                            (447,005)              -                      -          (447,005)
   Payment of debt, net                                      (238,365)              -                (33,404)         (271,769)
   Common and preferred stock dividends paid                  (65,018)              -                      -           (65,018)
   Other                                                        7,153               -                  1,894             9,047
   Net intercompany accounts                                  (73,193)        (87,265)               160,458                 -
                                                                                                                             -
                                                       ------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities          (316,548)        (87,265)               128,948          (274,865)
                                                       ------------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents                   $   2,250       $   7,813              $  63,382         $  73,445
Cash and Cash Equivalents at Beginning of Period               88,308           6,472                 75,837           170,617
                                                       ------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                  $  90,558       $  14,285              $ 139,219         $ 244,062
                                                       ========================================================================
</TABLE>

<TABLE>
<CAPTION>

---------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
---------------------------------------------------------------------------------------------------------------------------------
                                                                   Three Months Ended March 31, 2002
                                                         ------------------------------------------------------------------------
                                                                Guarantor         KEDLI          Other Subsidiaries   Consolidated
                                                         ------------------------------------------------------------------------
<S>                                                             <C>           <C>                     <C>              <C>
Operating Activities
Net Cash Provided by (Used in) Operating Activities            $  60,515       $ 302,490             $  (30,456)       $ 332,549
                                                         ------------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                -         (29,168)              (214,985)        (244,153)
                                                         ------------------------------------------------------------------------
Net Cash Used in Investing Activities                                  -         (29,168)              (214,985)        (244,153)
                                                         ------------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                          34,058               -                      -           34,058
   Payment of debt, net                                           (9,947)              -                (14,955)         (24,902)
   Common and preferred stock dividends paid                     (63,683)              -                      -          (63,683)
   Other                                                           8,127               -                (10,547)          (2,420)
   Net intercompany accounts                                     124,019        (273,322)               149,303                -
                                                                                                                               -
                                                         ------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities               92,574        (273,322)               123,801          (56,947)
                                                         ------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents           $ 153,089       $       -             $ (121,640)       $  31,449
Cash and Cash Equivalents at Beginning of Period                       -               -                159,252          159,252
                                                         ------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                     $ 153,089       $       -             $   37,612        $ 190,701
                                                         ========================================================================
</TABLE>



                                       30
<PAGE>


Item 2. Management's  Discussion and Analysis of Financial Condition and Results
of Operations

Consolidated Review of Results
------------------------------

The following is a summary of transactions  affecting comparative earnings and a
discussion of material  changes in revenues and expenses during the three months
ended  March 31,  2003,  compared  to the three  months  ended  March 31,  2002.
Capitalized terms used in the following  discussion,  but not otherwise defined,
have the same  meaning as when used in the Notes to the  Consolidated  Financial
Statements included under Item 1. References to "KeySpan", "we", "us", and "our"
mean KeySpan Corporation, together with its consolidated subsidiaries.

Operating  income by segment,  as well as  consolidated  earnings  available for
common stock is set forth in the following table for the periods indicated.

--------------------------------------------------------------------------------
(In Thousands of Dollars, Except per Share)
-------------------------------------------------------------------------------

Quarter Ended March 31,                                 2003            2002
-------------------------------------------------------------------------------
Gas Distribution                                      $364,937        $331,019
Electric Services                                       39,670          61,494
Energy Services                                         (9,148)         (9,358)
Energy Investments                                      60,057          20,376
Eliminations and other                                  (4,551)         (1,659)
-------------------------------------------------------------------------------
Operating Income                                       450,965         401,872
Other Income and (Deductions)                          (65,041)        (61,932)
Income taxes                                           142,833         125,309
-------------------------------------------------------------------------------
Income before cumulative effect
   of a change in accounting principle                 243,091         214,631
Cumulative effect of a change
   in accounting principle (See Note 7)                    174               -
-------------------------------------------------------------------------------
Net Income                                             243,265         214,631
Preferred stock dividend requirements                    1,461           1,476
-------------------------------------------------------------------------------
Earnings for Common Stock                             $241,804        $213,155
-------------------------------------------------------------------------------
Basic Earnings per Share
    Income before cumulative effect
       of a change in accounting principle              $ 1.54          $ 1.52
   Change in accounting principle                            -               -
-------------------------------------------------------------------------------
                                                        $ 1.54          $ 1.52
-------------------------------------------------------------------------------

As indicated in the above table, operating income increased by $49.1 million, or
12%, for the quarter ended March 31, 2003, compared to the corresponding  period
last year. The increase in operating  income  reflects  higher earnings from the
Energy Investments and Gas Distribution segments,  somewhat offset by a decrease
in earnings from the Electric  Services segment.  The Energy Investment  segment
benefited from higher  earnings  associated  with gas exploration and production
activities  as a result of  significantly  higher  realized gas prices.  The Gas


                                       31
<PAGE>

Distribution  segment  benefited  from  significantly  colder weather during the
first  quarter of 2003  compared to the first  quarter of 2002,  as well as from
load growth.  Lower results from the Electric  Services segment are attributable
to higher operating costs as a result of increases in plant maintenance expenses
and pension and other  postretirement  costs, as well as lower capacity revenues
from our merchant  generating  facility.  (See the discussion  under the caption
"Review of Operating Segments" for further details on each segment.)

Included in Other Income and  Deductions  are interest  charges of $68.9 million
and  $72.6  million  for the  three  months  ended  March  31,  2003  and  2002,
respectively.  The decrease in interest expense of $3.7 million, or 5%, reflects
the  benefits  associated  with  interest  rate  swaps.  In  February  2003,  we
terminated  an  interest  rate swap  agreement  with a  notional  amount of $270
million.  This swap was used to hedge a portion of outstanding  promissory notes
that were issued to the Long Island Power Authority  ("LIPA") in connection with
the  KeySpan/Long   Island  Lighting  Company  ("LILCO")  business   combination
completed in May 1998.  In March 2003, we called  approximately  $447 million of
the outstanding  promissory notes and recorded debt redemption  charges of $18.2
million in Other Income and  Deductions.  The cash proceeds from the termination
of the interest rate hedge were $18.4 million, of which $8.1 million represented
accrued swap interest.  The difference between the termination settlement amount
and the amount of accrued interest,  $10.3 million, was recorded to earnings (as
an adjustment to interest  expense) in the first quarter of 2003 and effectively
offset a portion of the redemption charges.

In  November  2002,  we  terminated  two  interest  rate  swap  agreements.  The
difference  between the termination  settlement amount and the amount of accrued
swap interest,  $57.4 million,  is currently  being amortized to earnings (as an
adjustment to interest  expense) on a level yield basis over the remaining lives
of the originally hedged debt obligations. The combination of the termination of
the interest  rate swap  agreement in February  2003 ($10.3  million),  plus the
amortization of last year's  terminated swap agreement  reduced interest expense
by $13.9 million for the three months ended March 31, 2003.  The use of interest
rate swaps reduced  interest  expense by $10.9  million  during the three months
ended  March 31,  2002.  (See Note 6 to the  Consolidated  Financial  Statements
"Hedging  and  Derivative  Financial  Instruments"  for a  description  of these
instruments.)

Also  included  in  Other  Income  and  Deductions  is a gain of  $19.0  million
reflecting  the  monetization  of a portion  of our  ownership  interest  in The
Houston  Exploration  Company  ("Houston  Exploration"),  a gas  exploration and
production  subsidiary.  On February 26, 2003, we reduced our ownership interest
in Houston  Exploration from 66% to approximately  56% following the repurchase,
by  Houston  Exploration,  of three  million  shares  of common  stock  owned by
KeySpan.  Income  taxes  were  not  provided  on  this  transaction,  since  the
transaction  was  structured  as a return of  capital.  Further,  in July  2002,
Houston  Exploration  received  an  abatement  of  severance  taxes for  certain
qualifying  wells.  As a result of this  abatement,  during the first quarter of
2003  Houston  Exploration  recorded a $10.6  million  severance  tax refund for
severance taxes paid in 2002 and earlier periods,  which has also been reflected
in Other Income and Deductions.  Offsetting,  to some extent,  these benefits to
Other Income and Deductions is the adjustment for minority interest.


                                       32
<PAGE>


The remaining  major  components  reflected in Other Income and  Deductions  are
equity  earnings  associated  with our  ownership  interest in the  Iroquois Gas
Transmission System LP and subsidiaries located in Northern Ireland,  which have
remained  consistent with the prior year, as well as carrying charges on certain
regulatory assets.

The  increase  in income tax  expense  generally  reflects  the higher  level of
pre-tax  income for the first  quarter of 2003,  compared  to the  corresponding
period  last year.  Further,  during the first  quarter of 2002,  we recorded an
adjustment to deferred  income taxes of $177.7 million  reflecting a decrease in
the tax basis of the assets acquired at the time of the  KeySpan/LILCO  business
combination.  This adjustment was a result of a revised  valuation study and the
filing of an amended tax return. Concurrent with the deferred tax adjustment, we
reduced  current  income taxes  payable by $183.2  million,  resulting in a $5.5
million income tax benefit.

Earnings  available  for common  stock for the three months ended March 31, 2003
increased by $28.6 million, or $0.02 per share, compared to the same period last
year.  Average  common shares  outstanding  for the quarter ended March 31, 2003
increased by 12%,  primarily  reflecting  the issuance of 13.9 million shares of
common stock on January 17, 2003, as well as the  re-issuance  of shares held in
treasury  pursuant to dividend  reinvestment  and employee  benefit plans.  This
increase  in average  common  shares  outstanding  reduced  first  quarter  2003
earnings per share by $0.19  compared to the  corresponding  period in 2002.  To
reduce the  dilutive  effect of the  equity  offering  we  redeemed a portion of
outstanding  promissory notes that were issued to LIPA, as previously mentioned.
Interest  savings  associated  with this  redemption  are  estimated to be $15.6
million after-tax, or $0.09 per share, in 2003.

Consolidated earnings are seasonal in nature due to the significant contribution
to earnings of the gas distribution  operations.  As a result, we expect to earn
most of our annual earnings in the first and fourth quarters of our fiscal year,
and breakeven or marginally  profitable  earnings are anticipated to be achieved
in the second and third quarters of our fiscal year.

Review of Operating Segments
----------------------------

In response to new disclosure regulations adopted by the Securities and Exchange
Commission as part of its  implementation  of the  Sarbanes-Oxley  Act of 2002 -
specifically  Regulation  G  which  became  effective  March  2003 - we  will be
reporting all of KeySpan's segment results on an Operating Income basis for 2003
and 2002.  Management believes that this Generally Accepted Accounting Principle
(GAAP)  based  measure  provides  a  true  indication  of  KeySpan's  underlying
performance  associated  with its  operations.  The following is a discussion of
financial  results  achieved by  KeySpan's  operating  segments  presented on an
Operating Income basis.



                                       33
<PAGE>


Gas Distribution

KeySpan Energy Delivery New York ("KEDNY") provides gas distribution  service to
customers in the New York City Boroughs of Brooklyn, Staten Island and a portion
of Queens,  and KeySpan  Energy  Delivery  Long Island  ("KEDLI")  provides  gas
distribution  service to  customers  in the Long  Island  counties of Nassau and
Suffolk and the  Rockaway  Peninsula  of Queens  County.  Four gas  distribution
companies - Boston Gas Company,  Colonial Gas  Company,  Essex Gas Company,  and
EnergyNorth  Natural Gas Inc., each doing business under the name KeySpan Energy
Delivery New England ("KEDNE"), provide gas distribution service to customers in
Massachusetts and New Hampshire.

The table below  highlights  certain  significant  financial  data and operating
statistics  for the Gas  Distribution  segment  for the periods  indicated.  Net
revenues  for 2002 have been  restated  to reflect a  reclassification  of gross
receipt  taxes  from  revenue  taxes  to  state  income  taxes,  which is not an
operating income measure.
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                                                          Three Months Ended March 31,
(In Thousands of Dollars)                                                  2003                   2002
-----------------------------------------------------------------------------------------------------------
<S>                                                                      <C>                    <C>
Revenues                                                                $ 1,832,701            $ 1,222,966
Cost of gas                                                               1,154,132                613,584
Revenue taxes                                                                38,616                 32,556
-----------------------------------------------------------------------------------------------------------
Net Revenues                                                                639,953                576,826
-----------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                                               166,090                145,539
   Depreciation and amortization                                             70,817                 63,018
   Operating taxes                                                           38,109                 37,250
-----------------------------------------------------------------------------------------------------------
Total Operating Expenses                                                    275,016                245,807
-----------------------------------------------------------------------------------------------------------
Operating Income                                                            364,937                331,019
-----------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH)                                    155,666                116,518
Transportation - Electric
   Generation (MDTH)                                                          5,003                 13,359
Other Sales (MDTH)                                                           53,670                 62,912
Warmer (Colder) than Normal - New York                                         (8.5)%                18.0%
Warmer (Colder) than Normal - New England                                     (10.0)%                16.0%
-----------------------------------------------------------------------------------------------------------
</TABLE>
An MDTH is 10,000  therms  (British  Thermal  Units) and  reflects  the  heating
content of  approximately  one million  cubic feet of gas. A therm  reflects the
heating content of  approximately  100 cubic feet of gas. One billion cubic feet
(BCF) of gas equals approximately 1,000 MDTH.



                                       34
<PAGE>

Net Revenues

Net gas revenues  (revenues less the cost of gas and  associated  revenue taxes)
from our gas distribution  operations increased by $63.1 million, or 11%, in the
first quarter of 2003 compared to same quarter last year.  Both our New York and
New England based gas distribution  operations  benefited from the significantly
colder  than normal  weather  experienced  throughout  the  Northeastern  United
States.  Based on heating degree days, weather for the first quarter of 2003 was
approximately 8.5%-10% colder than normal and approximately 35% colder than last
year in our New York and New England service territories.

Net revenues from firm gas customers  (residential,  commercial  and  industrial
customers) in our New York service territory  increased by $29.1 million for the
first quarter of 2003 compared to the same period last year. The  combination of
conversions of oil heating  customers to natural gas, as well as higher customer
consumption  due to the colder than normal  weather  added $38.9  million to net
revenues during the first quarter of 2003. However, KEDNY and KEDLI each operate
under a utility  tariff that contains a weather  normalization  adjustment  that
significantly  offsets  variations in firm net revenues due to  fluctuations  in
normal  weather.  These weather  normalization  adjustments  resulted in a $19.2
million refund to firm gas customers during the first quarter of 2003.  Further,
included  in net  revenues  is the  recovery  of  certain  taxes that added $9.4
million to net  revenues  during  the first  quarter  of 2003.  These  revenues,
however,  do not impact net income  since the taxes they are designed to recover
are expensed as amortization  charges and income taxes,  as appropriate,  on the
Consolidated Statement of Income.

Net  revenues  from firm gas  customers  in our New  England  service  territory
increased by $19.9  million for the first  quarter of 2003  compared to the same
period  last year.  The  combination  of  conversions  to natural gas as well as
higher  customer  consumption  due to the colder than normal weather added $35.7
million to net revenues  during the first quarter of 2003. The gas  distribution
operations  of  our  New  England  based  subsidiaries  do not  have  a  weather
normalization  adjustment.  To  mitigate  the effect of  fluctuations  in normal
weather  patterns  on KEDNE's  results of  operations  and cash  flows,  weather
derivatives were in place for the 2002/2003 winter heating season. Since weather
during the first  quarter of 2003 was 10% colder  than normal in the New England
service territory, we recorded an $11.9 million reduction to revenues to reflect
the loss on  these  derivative  transactions.  (See  Note 6 to the  Consolidated
Financial Statements "Hedging and Derivative Financial  Instruments" for further
information).  Further,  included in net revenues for the first quarter of 2002,
was a  benefit  of $3.9  million  as a result  of a  favorable  ruling  from the
Massachusetts  Supreme  Judicial  Court  relating  to the  appeal by Boston  Gas
Company of its Performance Based Rate Plan ("PBR").

Firm gas  distribution  rates in the first  quarter of 2003,  other than for the
recovery of gas costs, have remained substantially  unchanged from rates charged
last year in all of our service territories.

In our large-volume  heating and other interruptible  (non-firm) markets,  which
include large apartment houses, government buildings and schools, gas service is
provided  under rates that are  designed to compete  with prices of  alternative
fuel,  including  No. 2 and No. 6 grade  heating oil. Net revenues from sales to
these  markets  increased  by $14.1  million  during  the first  quarter of 2003
compared  to same  period  last  year as a result  of  aggressive  pricing.  The
majority of interruptible profits earned by KEDNE and KEDLI are returned to firm
customers as an offset to gas costs.


                                       35
<PAGE>


We are  committed  to our  expansion  strategies  initiated  during the past few
years. We believe that significant growth opportunities exist on Long Island and
in our New  England  service  territories.  We  estimate  that  on  Long  Island
approximately 35% of the residential and multi-family markets, and approximately
55% of the  commercial  market,  currently  use natural  gas for space  heating.
Further, we estimate that in our New England service  territories  approximately
50% of the residential and multi-family  markets,  and  approximately 45% of the
commercial market, currently use natural gas for space heating purposes. We will
continue to seek growth,  in all our market  segments,  through the expansion of
our gas  distribution  system,  as well as through the conversion of residential
homes  from   oil-to-gas   for  space  heating   purposes  and  the  pursuit  of
opportunities to grow multi-family, industrial and commercial markets.

Firm Sales, Transportation and Other Quantities

Firm gas sales and transportation  quantities  increased by 34% during the three
months ended March 31, 2003,  compared to the same period in 2002, due to higher
customer consumption as a result of the significantly colder weather, as well as
from  conversions  to natural  gas.  Net  revenues are not affected by customers
opting to purchase  their gas supply from other  sources,  since  delivery rates
charged to  transportation  customers  generally are the same as delivery  rates
charged to full sales service  customers.  Transportation  quantities related to
electric generation reflect the transportation of gas to our electric generating
facilities  located on Long  Island.  Net revenues  from these  services are not
material.

Other sales quantities include on-system  interruptible  quantities,  off-system
sales quantities  (sales made to customers  outside of our service  territories)
and  related  transportation.  During  the  first  quarter  of  2003,  we had an
agreement  with Coral  Resources,  L.P.  ("Coral"),  a  subsidiary  of Shell Oil
Company, under which Coral assisted in the origination,  structuring,  valuation
and execution of  energy-related  transactions  on behalf of KEDNY and KEDLI. We
also  had  a  portfolio  management  contract  with  Entergy-Koch,  under  which
Entergy-Koch  provided all of the city gate supply requirements at market prices
and  managed  certain  upstream  capacity,  underground  storage and term supply
contracts for KEDNE. Our agreements with Coral and Entergy-Koch expired on March
31, 2003 and were renewed through March 31, 2006.

Purchased Gas for Resale

The  increase in gas costs for the first  quarter of 2003  compared to the first
quarter of 2002 of $540.6  million,  or 88%,  reflects an increase of 40% in the
price per dekatherm of gas purchased,  and a 34% increase in the quantity of gas
purchased.  Fluctuations in utility gas costs associated with firm gas customers
have no impact on operating  results.  The current gas rate structure of each of
our gas distribution  utilities  includes a gas adjustment  clause,  pursuant to
which  variations  between  actual gas costs  incurred  and gas costs billed are
deferred and refunded to or collected from customers in a subsequent period.



                                       36
<PAGE>


Operating Expenses

Operating expenses during the first quarter of 2003 compared to the same quarter
last year have  increased  by $29.2  million,  or 12%. The increase in operating
expense  in  2003  is  attributable,  in  part,  to  higher  pension  and  other
postretirement benefits which increased by $9.2 million, net of amounts deferred
and subject to regulatory true-ups, over the level incurred in 2002. The cost of
these  benefits has risen  primarily as a result of lower actual returns on plan
assets,  as well as increased  health care costs.  Further,  the colder  weather
experienced  in the first  quarter  of 2003  resulted  in  increased  repair and
maintenance work on our gas distribution infrastructure that increased operating
expenses by approximately  $6 million.  Also, the bad debt reserve has increased
primarily as a result of higher account  receivables due to the cold weather and
higher  cost  of  gas  purchased.  Depreciation  and  amortization  expense  has
increased as a result of the continued expansion of the gas distribution system.
Further,  included in depreciation and amortization  expense is the amortization
of certain  property taxes  previously  deferred and currently  being  recovered
through revenues.

Other Matters

To take advantage of the anticipated gas sales growth  opportunities  in our New
York  service  territory,  in 2000 we formed the  Islander  East  Pipeline,  LLC
("Islander East"), a limited liability company in which a KeySpan subsidiary and
a subsidiary of Duke Energy Corporation each own a 50% equity interest. Islander
East has obtained all required permits in New York State for the construction of
the facility.  However,  the State of Connecticut has issued a moratorium on the
issuance of permits  relating to the  construction of energy projects until June
2003.  Islander East has therefore  been unable to obtain the necessary  permits
from the State of  Connecticut  at this time.  Islander East has also appealed a
denial by the State of Connecticut of the coastal zone management  permit to the
U.S.  Department of Commerce and such appeal is currently pending.  Assuming the
receipt of  approvals  from the State of  Connecticut  by  September  2003,  the
Islander  East  pipeline is expected to begin  operating by year-end  2004.  The
pipeline will  transport  260,000 DTH daily to the Long Island and New York City
energy  markets,  enough  fuel to heat  600,000  homes,  as well as  allow us to
further diversify the geographic sources of our gas supply.  Various options for
the financing of this pipeline are currently being evaluated.

Electric Services

The Electric  Services segment  primarily  consists of subsidiaries that own and
operate oil and gas fired  electric  generating  plants in the Borough of Queens
(the  "Ravenswood  facility")  and the  counties  of Nassau and  Suffolk on Long
Island. In addition,  through long-term  contracts of varying lengths, we manage
the electric transmission and distribution ("T&D") system, the fuel and electric
purchases, and the off-system electric sales for LIPA.



                                       37
<PAGE>



Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.

-------------------------------------------------------------------------------
                                               Three Months Ended March 31,
(In Thousands of Dollars)                      2003                   2002
-------------------------------------------------------------------------------
Revenues                                     $ 334,419               $ 314,710
Purchased fuel                                  79,268                  53,993
-------------------------------------------------------------------------------
Net Revenues                                   255,151                 260,717
-------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                  161,304                 148,119
   Depreciation                                 16,538                  13,733
   Operating taxes                              37,639                  37,371
-------------------------------------------------------------------------------
Total Operating Expenses                       215,481                 199,223
-------------------------------------------------------------------------------
Operating Income                                39,670                  61,494
-------------------------------------------------------------------------------
Electric sales (MWH)*                          767,349               1,091,243
Capacity(MW)*                                    2,200                   2,200
Cooling degree days                                N/A                    N/A
-------------------------------------------------------------------------------

*Reflects the operations of the Ravenswood facility only.

Net Revenues

Total  electric net  revenues  decreased  by $5.6  million,  or 2%, in the first
quarter of 2003,  compared to the same quarter of 2002.  Lower  comparative  net
revenues from the Ravenswood  facility of $12.9 million were offset, in part, by
net revenues from the Glenwood  Landing and Port  Jefferson  electric  "peaking"
facilities  located on Long Island.  The Glenwood facility was placed in service
on June 1, 2002, while the Port Jefferson facility was placed in service on July
1, 2002. Net revenues from these  facilities  were $7.9 million during the three
months ended March 31, 2003. Net revenues from the LIPA service  agreements were
consistent with last year.

As mentioned,  net revenues from the Ravenswood  facility were $12.9 million, or
18% lower during the first quarter of 2003,  compared to the same period in 2002
reflecting,  primarily,  a decrease in capacity sales of $11.8 million,  or 20%.
Lower  capacity  revenues  reflect  more  competitive  pricing  by the  electric
generators  that bid into the New York  Independent  System  Operator  ("NYISO")
energy  market which  lowered  capacity  clearing  prices by  approximately  26%
compared to last year. Net revenues from energy sales remained  relatively  flat
compared to last year. Due to a major  overhaul of our largest steam  generator,
energy sales  quantities were lower during the first quarter of 2003 compared to
the same period last year.  However,  the impact of lower sales  quantities were
offset by significantly higher "spark-spreads" (the selling price of electricity
less cost of fuel).



                                       38
<PAGE>


The rules and  regulations  for  capacity,  energy sales and the sale of certain
ancillary  services  to the NYISO  energy  markets  continue  to evolve  and the
Federal  Energy  Regulatory   Commission  ("FERC")  has  adopted  several  price
mitigation  measures that have adversely  impacted  earnings from the Ravenswood
facility.  Certain of these  mitigation  measures are still subject to rehearing
and possible  judicial  review.  The final  resolution of these issues and their
effect on our financial position, results of operations and cash flows cannot be
fully determined at this time. (See KeySpan's 2002 Annual Report on Form 10K for
the Year Ended December 31, 2002 Item 7. Management's Discussion and Analysis of
Financial  Condition  and Results of  Operations  under the caption  "Market and
Credit Risk Management Activities" for a further discussion of these matters.)

Operating Expenses

Operating  expenses  increased by $16.3 million,  or 8%, in the first quarter of
2003  compared  to the same  quarter  of 2002,  primarily  as a result of higher
comparative pension and other postretirement  benefits.  LIPA reimburses KeySpan
for costs directly incurred by KeySpan in providing service to LIPA,  subject to
certain sharing  provisions.  These  reimbursements  are based on  predetermined
estimates of operating costs.  Variations between certain actual operating costs
incurred (i.e.  postretirement  costs and property taxes) and the  predetermined
estimates  are deferred and  refunded to or  collected  from LIPA in  subsequent
periods.  As a  result  of an  adjustment  recorded  in  2002  relating  to this
"true-up", comparative pension and other postretirement costs were approximately
$11 million  higher in this  quarter  compared to this time last year.  Further,
plant  maintenance  costs were $5.3 million  higher  during the first quarter of
2003  compared to the first  quarter of 2002,  due to the major  overhaul of our
largest steam generator as previously mentioned.

Other Matters

During  2002,  construction  began  on a new 250 MW  combined  cycle  generating
facility  at the  Ravenswood  facility  site.  The new  facility  is expected to
commence  operations  in late 2003.  The capacity and energy  produced from this
plant are  anticipated  to be sold into the NYISO  energy  markets.  We are also
progressing  through  the siting  process  before  the New York  State  Board on
Electric  Generation  Siting  and the  Environment  with a  proposal  to build a
similar 250 MW combined cycle electric  generating  facility on Long Island.  On
February 4, 2003, an Examiners' Recommended Decision was issued recommending the
granting of a certificate of  environmental  capability and public need for this
proposed facility.  In addition,  as part of our growth strategy, we continually
evaluate the possible  acquisition  of additional  generating  facilities in the
Northeast. However, we are unable to predict when or if any such facilities will
be  acquired  and the  effect  any such  acquired  facilities  will  have on our
financial condition, results of operations or cash flows.



                                       39
<PAGE>

Energy Services

The Energy Services segment primarily  includes  companies that provide services
through three lines of business to clients primarily located within the New York
City  metropolitan  area,  including New Jersey and  Connecticut,  as well as in
Rhode  Island,  Pennsylvania,  Massachusetts  and New  Hampshire.  The  lines of
business are Home Energy Services, Business Solutions, and Fiber Optic Services.

The  table  below  highlights  selected  financial  information  for the  Energy
Services segment.

--------------------------------------------------------------------------------
                                                  Three Months Ended March 31,
(In Thousands of Dollars)                         2003                   2002
--------------------------------------------------------------------------------
Revenues                                       $ 193,797              $ 241,559
Less: cost of gas and fuel                        60,153                 66,155
--------------------------------------------------------------------------------
Net Revenues                                     133,644                175,404
Other operating expenses                         142,792                184,762
--------------------------------------------------------------------------------
Operating Income                                  (9,148)                (9,358)
--------------------------------------------------------------------------------


Net revenues  decreased by 24% during the first  quarter of 2003 compared to the
same  period  last year,  primarily  as a result of the  discontinuation  of the
general  contracting  business  of  one  of our  subsidiaries.  Excluding  those
operations,  net  revenues  decreased  by 7% during  the first  quarter  of 2003
compared to the same quarter last year,  due to lower margins  realized on large
construction projects as result of the continued down turn in the economy.

Operating  Income for the Business  Solutions group of companies,  which provide
mechanical  contracting,   plumbing,  engineering  and  consulting  services  to
commercial,  institutional,  and industrial customers, decreased by $2.0 million
for the first  quarter of 2003  compared  to the  corresponding  quarter of last
year. This decrease reflects the slow down in the economy, which has delayed the
start-up  of  certain  engineering  and  construction   projects.   Further,  as
mentioned,  the continued down turn in the economy has lowered margins  realized
on construction  projects currently in progress.  This is further reflected by a
backlog of  approximately  $479 million at March 31, 2003,  compared to $ 514 at
December 31, 2002 and $647 million at March 31, 2002.

Offsetting  the results of the Business  Solutions  group of  companies,  was an
increase in  operating  income of $2.2 million  associated  with the Home Energy
Services  group of companies.  These  companies  provide  residential  and small
commercial  customers  with service and  maintenance  contracts,  as well as the
retail marketing of natural gas and  electricity.  In the first quarter of 2002,
these companies recorded an additional reserve for bad debts of approximately $5
million.


                                       40
<PAGE>


Energy Investments

The Energy  Investment  segment  consists of our gas  exploration and production
operations, certain other domestic and international energy-related investments,
as well as certain  technology  related  investments.  Our gas  exploration  and
production  subsidiaries,   Houston  Exploration  and  KeySpan  Exploration  and
Production  LLC  ("KES  E&P")  are  engaged  in  gas  and  oil  exploration  and
production,  and the development and acquisition of domestic natural gas and oil
properties.  In line  with our  strategy  of  monetizing  or  divesting  certain
non-core  assets,  in October  2002 we  monetized a portion of our assets in the
joint venture  drilling  program with Houston  Exploration that was initiated in
1999.  Further,  in February 2003, we reduced our ownership  interest in Houston
Exploration  to  approximately  56% (from the previous level of 66%) through the
repurchase,  by Houston  Exploration,  of three  million  shares of common stock
owned by KeySpan.  The net  proceeds of  approximately  $79 million  received in
connection  with this  repurchase  were  used to pay down  short-term  debt.  We
realized a $19.0  million  gain on this  transaction  that was recorded in Other
Income and Deductions in the Consolidated Statement of Income. Income taxes were
not provided on this  transaction,  since the  transaction  was  structured as a
return of capital.

Selected  financial data and operating  statistics for our gas  exploration  and
production  activities  are set forth in the  following  table  for the  periods
indicated.
<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------
                                                                Three Months Ended March 31,
(In Thousands of Dollars)                                        2003                   2002
------------------------------------------------------------------------------------------------
<S>                                                            <C>                      <C>
Revenues                                                      $ 127,847                $ 76,926
Depletion and amortization expense                               47,443                  41,446
Other operating expenses                                         24,814                  15,655
------------------------------------------------------------------------------------------------
Operating Income                                                 55,590                  19,825
------------------------------------------------------------------------------------------------
Natural gas and oil production (Mmcf)                            26,086                  25,670
Natural gas (per Mcf) realized                                $    4.91                $   2.98
Natural gas (per Mcf) unhedged                                $    6.35                $   2.29
------------------------------------------------------------------------------------------------
</TABLE>

*Operating  income above  represents  100% of our gas exploration and production
subsidiaries' results for the periods indicated. Gas reserves and production are
stated in BCFe and Mmcfe, which includes equivalent oil reserves.

The  increase in  operating  income of $35.8  million for the three months ended
March 31, 2003,  compared to the corresponding  period last year,  reflects,  in
part, a significant  increase in revenues offset, to some extent, by an increase
in operating expenses  associated with higher production  volumes.  Revenues for
the first quarter of 2003,  compared to the first quarter of 2002,  benefited by
the  significant  increase in comparative  average  realized gas prices (average
wellhead  price  received for  production  including  hedging gains and losses).
Average  realized  gas  prices  increased  65% for the  first  quarter  of 2003,
compared with the corresponding  period last year (from $2.98 per Mcf in 2002 to
$4.91  per Mcf in 2003).  Revenues  also  benefited  from an  increase  of 2% in
production volumes.


                                       41
<PAGE>


The average  realized gas price for 2003 was 77% of the average unhedged natural
gas price,  resulting in revenues  that were $34.7  million  lower than revenues
that would have been achieved if derivative  financial  instruments had not been
in place during the first quarter of 2003. Houston Exploration hedged almost 70%
of its 2003 first quarter  production,  principally  through the use of costless
collars.  The average  realized gas price for the first quarter of 2002 was 130%
of the average unhedged natural gas price, resulting in revenues that were $17.0
million  higher  than  revenues  that would  have been  achieved  if  derivative
financial  instruments  had not been employed  during the first quarter of 2002.
These derivative  instruments are designed to provide Houston Exploration with a
more predictable cash flow, as well as to reduce its exposure to fluctuations in
natural  gas  prices.  At March 31,  2003  Houston  Exploration  had  derivative
positions in place to hedge  approximately  67% of its estimated 2003 production
and  approximately  38% of its  estimated  2004  production,  again  principally
through the use of costless collars.  Depending upon market conditions,  Houston
Exploration may enter into additional  derivative positions during 2003 to hedge
a  larger  portion  of  its  estimated  2004  production.  (See  Note  6 to  the
Consolidated   Financial   Statements,   "Hedging   and   Derivative   Financial
Instruments"  for  further  information  on  these  derivative  positions.)

The depletion  rate was $1.77 per Mcf for the three months ended March 31, 2003,
compared to $1.63 per Mcf for the same period in 2002.  The  depletion  rate has
increased as Houston Exploration  completed the evaluation of several properties
that were  classified  as  unproved  during the fourth  quarter of 2002.  As the
evaluation  is  completed,  the costs  associated  with  these  properties  were
reclassified into the amortization base without  incremental  reserve additions.
In addition, future development costs have increased from prior year estimates.

The table below  indicates the net proved  reserves of our gas  exploration  and
production subsidiaries at December 31, 2002.

                                                  BCFe          %
-------------------------------------------------------------------
Houston Exploration                                650       96.7%
KSE E&P                                             22        3.3%
-------------------------------------------------------------------
Total                                              672      100.0%
-------------------------------------------------------------------



This segment also consists of KeySpan  Canada;  our 20% interest in Iroquois Gas
Transmission  System  LP  ("Iroquois");  and our  50%  interest  in the  Premier
Transmission Pipeline and 24.5% interest in Phoenix Natural Gas, both located in
Northern Ireland.

Selected  financial data and operating  statistics for our other  energy-related
investments are set forth in the following table for the periods indicated.

--------------------------------------------------------------------------------
                                                  Three Months Ended March 31,
(In Thousands of Dollars)                         2003                   2002
--------------------------------------------------------------------------------
Revenues                                        $ 26,464               $ 17,636
Operation and maintenance expense                 16,644                 14,056
Other operating expenses                           5,353                  3,029
--------------------------------------------------------------------------------
Operating Income                                   4,467                    551
--------------------------------------------------------------------------------


                                       42
<PAGE>


The increase in operating  income for the first  quarter of 2003 compared to the
same quarter last year primarily  reflects lower  comparative  losses associated
with  certain  technology-related   investments,  as  well  as  slightly  higher
operating  income  associated  with  our  Canadian  investments.   The  earnings
associated  with Iroquois and our Northern  Ireland  investments are recorded on
the equity method and appropriately recorded in Other Income and Deductions, and
are therefore not reflected in the above table.

We do not  consider  certain  businesses  contained  in the  Energy  Investments
segment to be part of our core asset  group.  We have stated in the past that we
may sell or  otherwise  dispose of all or a portion of our non-core  assets.  In
furtherance of this  objective,  we recently sold our  approximate 20% ownership
interest  in  Taylor  NGL  Limited  Partnership,  which  owns and  operates  two
extraction plants, one located in British Columbia, and one in Alberta,  Canada,
to AltaGas Services,  Inc. We are also in the process of monetizing a portion of
our  interests in KeySpan  Canada  through the  establishment  of an  open-ended
income fund trust (the "Fund") organized under the laws of Alberta,  Canada. The
Fund would initially  acquire an approximate  33% of the ownership  interests of
KeySpan  Canada through an indirect  subsidiary,  and would issue trust units to
the public through an initial public offering.  Each trust unit will represent a
beneficial  interest in the Fund and will be  registered  on the  Toronto  Stock
Exchange.  Based on current market conditions,  however, we cannot predict when,
or if, the KeySpan Canada  transaction,  or any such other sales or dispositions
of our  non-core  assets may take  place,  or the  effect  that any such sale or
disposition  may have on our financial  position,  results of operations or cash
flows.

Allocated Costs

We are subject to the  jurisdiction  of the SEC under the Public Utility Holding
Company Act ("PUHCA") as amended. As part of the regulatory provisions of PUHCA,
the SEC regulates various transactions among affiliates within a holding company
system.  In accordance with the SEC's  regulations  under PUHCA and the New York
State Public Service  Commission,  we have service  companies that provide:  (i)
traditional  corporate  and  administrative  services;  (ii)  gas  and  electric
transmission  and  distribution  systems  planning,  marketing,  and gas  supply
planning  and  procurement;  and (iii)  engineering  and  surveying  services to
subsidiaries. During the first quarter of 2003, these non-operating subsidiaries
incurred general corporate  expenses  primarily related to consulting,  auditing
and legal costs associated with the  implementation  of the  Sarbanes-Oxley  Act
that were not allocated to the various operating subsidiaries.

Liquidity

Cash flow from  operations  increased by $157.3 million during the first quarter
of 2003 compared to the same quarter last year. This increase reflects, in part,
significantly  higher  gas  prices,  which  benefited  our gas  exploration  and
production  operations.   Further,  outstanding  receivables  at  December  2002
associated with gas distribution  operations were significantly  higher than the
prior  year and,  therefore,  resulted  in higher  collections  during the first
quarter of 2003. In addition,  cash earnings were higher in the first quarter of
2003 compared to the same period last year,  due in part, to the  termination of
an interest rate swap, as well as the gain from the monetization of a portion of
our investment in Houston Exploration.


                                       43
<PAGE>


A substantial  portion of consolidated  revenues are derived from the operations
of businesses within the Electric  Services segment,  that are largely dependent
upon two large customers - LIPA and the NYISO.  Accordingly,  our cash flows are
dependent upon the timely payment of amounts owed to us by these customers.

At March 31, 2003, we had cash and temporary cash investments of $244.1 million.
During the three  months  ended  March 31,  2003,  we repaid  $238.4  million of
commercial paper and, at March 31, 2003,  $677.3 million of commercial paper was
outstanding at a weighted average annualized  interest rate of 1.37%. We had the
ability to borrow up to an additional  $622.7  million at March 31, 2003,  under
the terms of our credit facility.

KeySpan has an existing  364-day  revolving  credit  agreement with a commercial
bank syndicate of 16 banks totaling $1.3 billion. The credit facility is used to
back up the $1.3 billion commercial paper program. The fees for the facility are
subject to a ratings-based grid, with an annual fee of .075% on the total amount
of the revolving  facility.  The credit  agreement  allows for KeySpan to borrow
using  several  different  types  of  loans;  specifically,   Eurodollar  loans,
Adjustable Bank Rate ("ABR") loans, or competitively bid loans. Eurodollar loans
are based on the Eurodollar rate plus a margin of 42.5 basis points for loans up
to 33% of the facility,  and an additional  12.5 basis points for loans over 33%
of the total facility. ABR loans are based on the greater of the Prime Rate, the
base CD rate plus 1%, or the Federal Funds Effective Rate plus 0.5%. Competitive
bid loans are based on bid results requested by KeySpan from the lenders.  We do
not anticipate borrowing against this facility; however, if the credit rating on
our commercial  paper program were to be  downgraded,  it may be necessary to do
so.

The  credit  facility  contains  certain   affirmative  and  negative  operating
covenants,  including  restrictions  on KeySpan's  ability to mortgage,  pledge,
encumber  or  otherwise  subject its  property  to any lien,  as well as certain
financial  covenants  that  require  us  to,  among  other  things,  maintain  a
consolidated  indebtedness to consolidated  capitalization ratio of no more than
66%.

Under the terms of the credit facility,  KeySpan's debt-to-total  capitalization
ratio  reflects  80% equity  treatment  for the MEDS Equity  Units issued in May
2002. In addition,  the $425 million Ravenswood Master Lease is treated as debt.
At March 31, 2003, consolidated  indebtedness,  as calculated under the terms of
the credit facility, was 57.4% of consolidated capitalization. Violation of this
covenant could result in the termination of the credit facility and the required
repayment of amounts  borrowed  thereunder,  as well as possible  cross defaults
under  other  debt  agreements.   (See  discussion  under   "Off-Balance   Sheet
Arrangements" for an explanation of the Ravenswood Master Lease.)

The  credit  facility  also  requires  that net cash  proceeds  from the sale of
significant  subsidiaries  be  applied  to  reduce  consolidated   indebtedness.
Further,  an acceleration of indebtedness of KeySpan or one of its  subsidiaries
for borrowed  money in excess of $25 million in the  aggregate,  if not annulled
within 30 days after written notice,  would create an event of default under the
Indenture  dated  November  1,  2000,   between  KeySpan   Corporation  and  the
JPMorganChase Bank as Trustee. At March 31, 2003, KeySpan was in compliance with
all covenants.


                                       44
<PAGE>


Houston  Exploration has a revolving  credit facility with a commercial  banking
syndicate that provides  Houston  Exploration with a commitment of $300 million,
which can be  increased  at its option to a maximum of $350  million  with prior
approval from the banking syndicate. The credit facility is subject to borrowing
base  limitations,  initially  set at $300  million  and  will be  re-determined
semi-annually.  Up to $25 million of the  borrowing  base is  available  for the
issuance of letters of credit.  The credit facility matures on July 15, 2005, is
unsecured and ranks senior to all existing debt of Houston Exploration.

Under the Houston  Exploration  credit facility,  interest on base rate loans is
payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater
of the  federal  funds  rate  plus  0.50% or the  bank's  prime  rate plus (b) a
variable  margin  between 0% and 0.50%,  depending  on the amount of  borrowings
outstanding  under the credit facility.  Interest on fixed rate loans is payable
at a fixed rate equal to the sum of (a) a quoted  reserve  adjusted  LIBOR rate,
plus (b) a variable  margin between 1.25% and 2.00%,  depending on the amount of
borrowings outstanding under the credit facility.

Financial  covenants  require Houston  Exploration  to, among other things,  (i)
maintain an interest  coverage ratio of at least 3.00 to 1.00 of earnings before
interest,  taxes and depreciation  ("EBITDA") to cash interest;  (ii) maintain a
total  debt to EBITDA  ratio of not more than 3.50 to 1.00;  and (iii)  hedge no
more than 70% of natural gas production during any 12-month period. At March 31,
2003, Houston Exploration was in compliance with all financial covenants.

During the first quarter of 2003, Houston Exploration borrowed $18 million under
its credit  facility and repaid $40 million.  At March 31, 2003, $130 million of
borrowings  remained  outstanding at a weighted average annualized interest rate
of 3.31%. Also, $15.5 million was committed under outstanding  letters of credit
obligations.  At March 31,  2003,  $154.5  million  of  borrowing  capacity  was
available.

KeySpan Canada has two revolving credit  facilities with financial  institutions
in Canada.  Repayments  under these  agreements  totaled  approximately US $10.5
million  during the first quarter of 2003. At March 31, 2003,  approximately  US
$148.7 million was outstanding at a weighted average annualized interest rate of
3.65%.  KeySpan Canada  currently has available  borrowings of  approximately US
$38.4 million.  These revolving  credit  agreements  have been extended  through
January 2004. KeySpan is a guarantor under one of these credit facilities and an
event of default would exist  thereunder if KeySpan,  as guarantor,  falls below
investment  grade  rating or its  ratings  fall  below A3 (by  Moody's  Investor
Services)  or A-  (by  Standard  &  Poor's)  at a  time  when  its  consolidated
indebtedness,  as measured  using the same  criteria  employed  under  KeySpan's
credit facility, is greater than 66% of consolidated  capitalization or its cash
flow to interest  expense is less than 2.25 to 1.00. At March 31, 2003,  KeySpan
and KeySpan Canada were in compliance with all covenants.


                                       45
<PAGE>


On January 17, 2003,  KeySpan  sold 13.9  million  shares of common stock to the
open market and realized net proceeds of approximately $473 million.  All shares
were offered by KeySpan pursuant to the effective shelf  registration  statement
filed with the Securities and Exchange Commission.  Net proceeds from the equity
sale  were  used  initially  to pay  down  commercial  paper.  In  addition,  as
previously noted, we used the net proceeds of approximately $79 million received
in  February  2003 in  connection  with  the  partial  monetization  of  Houston
Exploration to repay short-term debt.

We  satisfy  our  seasonal  working  capital   requirements   primarily  through
internally generated funds and the issuance of commercial paper. We believe that
these  sources of funds are  sufficient  to meet our  seasonal  working  capital
needs. In addition,  we currently use treasury stock to satisfy the requirements
of our dividend  reinvestment and employee benefit plans.

Capital Expenditures and Financing

Construction Expenditures

The table below sets forth our  construction  expenditures by operating  segment
for the periods indicated:

------------------------------------------------------------------------------
                                                 Three Months Ended March 31,
(In Thousands of Dollars)                       2003                    2002
------------------------------------------------------------------------------
Gas Distribution                              $ 78,013               $ 84,366
Electric Services                               56,731                 88,544
Energy Investments                              84,309                 67,697
Energy Services                                  1,726                  3,546
------------------------------------------------------------------------------
                                             $ 220,779              $ 244,153
------------------------------------------------------------------------------


Construction  expenditures related to the Gas Distribution segment are primarily
for the renewal and  replacement  of mains and services and for the expansion of
the gas distribution system. Construction expenditures for the Electric Services
segment  reflect costs to: (i) maintain our generating  facilities;  (ii) expand
the  Ravenswood  facility;  and  (iii)  construct  new  Long  Island  generating
facilities as previously noted.  Construction expenditures related to the Energy
Investments  segment primarily reflect costs associated with gas exploration and
production   activities.   These  costs  are  related  to  the  exploration  and
development  of  properties  primarily in Southern  Louisiana and in the Gulf of
Mexico.  Expenditures  also include  development costs associated with the joint
venture with Houston  Exploration,  as well as costs related to KeySpan Canada's
gas processing facilities.

At March 31, 2003, total expenditures associated with the siting, permitting and
construction of the Ravenswood  expansion  project,  the siting,  permitting and
procurement  of equipment for the Long Island 250MW  combined  cycle  generation
plant,  and the siting and permitting of the Islander East pipeline project were
$270.4 million.


                                       46
<PAGE>


Financing

In connection with the KeySpan/LILCO  business combination,  KeySpan and certain
of its  subsidiaries  issued  promissory  notes to LIPA to support  certain debt
obligations assumed by LIPA. At December 31, 2002 the remaining principal amount
of promissory notes issued to LIPA was approximately  $600 million.  Under these
promissory notes,  KeySpan is required to obtain letters of credit to secure its
payment obligations if its long-term debt is not rated at least in the "A" range
by at least two nationally recognized  statistical rating agencies. In an effort
to mitigate the dilutive effect of the equity issuance previously mentioned,  in
March 2003, we called  approximately $447 million aggregate  principal amount of
such  promissory  notes at the  applicable  redemption  prices plus  accrued and
unpaid interest  through the dates of redemption.  Interest  savings  associated
with this redemption are estimated to be $15.6 million  after-tax,  or $0.09 per
share, in 2003.

In April 2003, we issued $300 million of  medium-term  and long-term  debt.  The
debt was issued in the  following  two series:  (i) $150 million 4.65% Notes due
2013; and (ii) $150 million 5.875% Notes due 2033. The proceeds of this issuance
were used to pay down outstanding commercial paper.

KeySpan has the ability under the Public Utility  Holding  Company Act ("PUHCA")
to issue up to $2.2 billion of securities  through December 31, 2003.  Following
the recent common stock offering  previously  mentioned and after accounting for
the shares of common  stock  expected  to be issued  for  employee  benefit  and
dividend reinvestment plans, we have approximately $25 million available for the
issuance of new securities under our current PUHCA  authorization.  However, the
issuance of securities in connection with the redemption of existing  securities
(including the promissory  notes  discussed  previously) is permitted  under our
PUHCA  authorization  notwithstanding  the  foregoing  limit.  We intend to seek
authorization from the SEC in the near term to enable us to, among other things,
issue  additional  securities in an aggregate  amount not yet determined.  It is
anticipated that this authorization will be obtained before the end of the year.

During 2003, we intend to issue  approximately $150 million of either taxable or
tax-exempt  long-term debt securities in a manner that will be exempt from PUCHA
restrictions.  We anticipate that the proceeds from the issuance will be used to
re-pay the outstanding  commercial  paper related to the construction of the two
Long Island  peaking-power  plants.  We will  continue  to evaluate  our capital
structure  and  financing  strategy  for 2003 and  beyond.  We believe  that our
current sources of funding (i.e.,  internally  generated  funds, the issuance of
additional securities as noted above, and the availability of commercial paper),
together with the cash proceeds from the recent equity offering,  are sufficient
to meet our anticipated working capital needs for the foreseeable future.



                                       47
<PAGE>


The following  table  represents  the ratings of our long-term debt at March 31,
2003.  Currently,  these ratings are all on stable outlook with the exception of
Standard & Poor's rating on KeySpan Corporation, which is on negative outlook.

--------------------------------------------------------------------------------
                             Moody's Investor      Standard
                                Services           & Poor's     FitchRatings
--------------------------------------------------------------------------------
KeySpan Corporation                A3                 A              A-
KEDNY                              A2                 A+             A+
KEDLI                              A2                 A+             A-
Boston Gas                         A2                 A2             N/A
Colonial Gas                       A                  A              N/A
--------------------------------------------------------------------------------


Off-Balance Sheet Arrangements

Guarantees

KeySpan has a number of financial  guarantees  with its  subsidiaries  that have
remained  substantially  unchanged  since  December 31, 2002. At March 31, 2003,
KeySpan  has fully and  unconditionally  guaranteed  certain  medium-term  notes
issued by KEDLI under KEDLI's current shelf registration,  as well as guaranteed
a revolving credit agreement associated with its Canadian  subsidiary.  Both the
medium-term  notes and  outstanding  borrowings  under the credit  facility  are
reflected on the Consolidated  Balance Sheet.  Further,  KeySpan has guaranteed:
(i) surety bonds associated with certain  construction  projects currently being
performed  by  subsidiaries  within the Energy  Services  segment;  (ii) certain
supply contracts,  margin accounts and purchase orders for certain subsidiaries;
(iii) the  obligations  of KeySpan  Ravenswood  LLC,  the lessee  under the $425
million Master Lease Agreement associated with the Ravenswood facility; and (iv)
certain  subsidiary  letters of credit.  KeySpan has also guaranteed $25 million
associated with a non-affiliated  company's line of credit. These guarantees are
not recorded on the Consolidated  Balance Sheet. At this time, we have no reason
to believe that our subsidiaries or the  non-affiliated  company will default on
their current  obligations.  However,  we cannot predict when or if any defaults
may take place or the impact such defaults may have on our consolidated  results
of operations, financial condition or cash flows (See Note 8 to the Consolidated
Financial  Statements,  "Financial  Guarantees  and  Contingencies"  and  Note 9
"Variable  Interest  Entity"  for  a  description  of  the  leasing  arrangement
associated with the Ravenswood Master Lease Agreement and additional information
regarding KeySpan's guarantees.)

Variable Interest Entity

We have an arrangement with a variable  interest entity through which we lease a
portion of the  Ravenswood  facility.  We acquired the Ravenswood  facility,  in
part, through the variable interest entity from The Consolidated  Edison Company
of New York  ("Consolidated  Edison")  on June 18, 1999 for  approximately  $597
million.  In order to reduce the initial  cash  requirements,  we entered into a
lease  agreement  (the "Master  Lease") with a variable  interest,  unaffiliated
financing entity that acquired a portion of the facility, three steam generating


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<PAGE>

units,  directly from Consolidated Edison and leased it to a KeySpan subsidiary.
The variable  interest  unaffiliated  financing entity acquired the property for
$425 million,  financed with debt of $412.3 million (97% of capitalization)  and
equity of $12.7 million (3% of capitalization). Monthly lease payments equal the
monthly  interest  expense on the debt  securities.  The Master Lease  currently
qualifies  as  an  operating  lease  for  financial   reporting  purposes  while
preserving  our  ownership  of the  facility  for federal  and state  income tax
purposes.

In January 2003, The Financial  Accounting  Standards Board (the "Board") issued
Interpretation No. 46 ("FIN 46"),  "Consolidation of Variable Interest Entities,
an Interpretation of ARB No. 51." This Interpretation would require us to, among
other things,  consolidate  this variable  interest entity for the first interim
period  ending after June 15,  2003,  so long as the current  variable  interest
structure remains intact. FIN 46 will require us to classify the Master Lease as
debt on the Consolidated  Balance Sheet at an amount approximately equal to fair
market value.  As previously  mentioned,  under the terms of our credit facility
the Master Lease is considered debt in the ratio of debt-to-total capitalization
and  therefore,  implementation  of FIN 46 will  have no  impact  on our  credit
facility.  Further,  we will be required to record an asset on the  Consolidated
Balance Sheet for an amount equal to the fair market value of the leased assets.
The Interpretation contains certain other provisions that we will be required to
implement in 2003 and such provisions may impact future earnings. (See Note 9 to
the  Consolidated  Financial  Statements  "Variable  Interest Entity" for a more
detailed description of the Master Lease and FIN 46 implementation issues.)

Contractual Obligations

KeySpan has certain contractual obligations related to its outstanding long-term
debt,  outstanding  credit facility  borrowings,  outstanding  commercial  paper
borrowings,  operating and capital  leases,  and demand charges  associated with
certain  commodity  purchases.  These  obligations  have remained  substantially
unchanged  since December 31, 2002.  (For  additional  details  regarding  these
obligations see KeySpan's  Annual Report on Form 10K for the Year Ended December
31, 2002, Item 7 Management's Discussion and Analysis of Financial Condition and
Results  of  Operations,  Note  6 to  those  Consolidated  Financial  Statements
"Long-Term Debt", as well as Note 7 to those Consolidated  Financial  Statements
"Contractual Obligations, Financial Guarantees and Contingencies.")

Discussions of Critical Accounting Policies and Assumptions

In preparing our financial  statements,  the  application of certain  accounting
policies  requires   difficult,   subjective  and/or  complex   judgments.   The
circumstances  that make these judgments  difficult,  subjective  and/or complex
have to do with the need to make estimates  about the impact of matters that are
inherently  uncertain.  Actual effects on our financial  position and results of
operations  may vary  significantly  from expected  results if the judgments and
assumptions underlying the estimates prove to be inaccurate.  At March 31, 2003,


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<PAGE>

KeySpan's   critical   accounting   policies  and   assumptions   have  remained
substantially  unchanged since December 31, 2002. Below is a brief discussion of
those  critical  accounting  policies  requiring such  subjectivity.  For a more
detailed  discussion of these  policies and  assumptions  see  KeySpan's  Annual
Report on Form 10K for the Year Ended  December 31, 2002,  Item 7.  Management's
Discussion  and  Analysis  of  Financial  Condition  and  Results of  Operations
"Discussion of Critical Accounting Policies and Assumptions."

Percentage of Completion Accounting

Percentage-of-completion  accounting is the prescribed  method of accounting for
long-term  construction  type contracts in accordance  with  Generally  Accepted
Accounting Principles and, accordingly,  the method used for revenue recognition
by the Energy Services segment.  Due to uncertainties  inherent within estimates
employed  to apply  percentage-of-completion  accounting,  it is  possible  that
estimates  will be revised  as project  work  progresses.  Changes in  estimates
resulting in additional  future costs to complete projects can result in reduced
margins or loss contracts.

Valuation of Goodwill

KeySpan records  goodwill on purchase  transactions,  representing the excess of
acquisition  cost over the fair value of net  assets  acquired.  In testing  for
goodwill impairment under Statement of Financial  Accounting  Standards ("SFAS")
142,  significant  reliance is placed upon estimated future cash flows requiring
broad  assumptions and significant  judgment by management.  Cash flow estimates
are determined  based upon future  commodity  prices,  customer rates,  customer
demand, operating costs, rate relief from regulators,  customer growth and other
items. A change in the fair value of our  investments  could cause a significant
change in the carrying value of goodwill.  While we believe that our assumptions
are reasonable,  actual results may differ from our projections. The assumptions
used to measure the fair value of our  investments are the same as those used by
us to prepare yearly operating  segment and consolidated  earnings and cash flow
forecasts.  In  addition,  these  assumptions  are used to set yearly  budgetary
guidelines.

Accounting for the Effects of Rate Regulation on Gas Distribution Operations

The financial  statements of the Gas Distribution segment reflect the ratemaking
policies and orders of the New York Public Service Commission ("NYPSC"), the New
Hampshire  Public  Utilities   Commission   ("NHPUC"),   and  the  Massachusetts
Department of Telecommunications and Energy ("DTE").

Four of our six regulated gas utilities  (KEDNY,  KEDLI,  Boston Gas Company and
EnergyNorth  Natural  Gas,  Inc.)  are  subject  to the  provisions  of SFAS 71,
"Accounting  for the Effects of Certain  Types of  Regulation."  This  statement
recognizes the actions of regulators,  through the ratemaking process, to create
future economic benefits and obligations affecting rate-regulated companies.


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<PAGE>


In separate  merger-related  orders issued by the DTE, the base rates charged by
Colonial  Gas Company and Essex Gas  Company  have been frozen at their  current
levels for a ten-year  period ending 2009.  Due to the length of these base rate
freezes,  the Colonial and Essex Gas Companies had previously  discontinued  the
application  of SFAS 71.

Rate  regulation is undergoing  significant  change as regulators  and customers
seek lower  prices for  utility  service and greater  competition  among  energy
service  providers.  In the event  that  regulation  significantly  changes  the
opportunity  for us to  recover  costs in the  future,  all or a portion  of our
regulated operations may no longer meet the criteria for the application of SFAS
71.  In  that  event,  a  write-down  of  our  existing  regulatory  assets  and
liabilities could result. In management's  opinion,  our regulated  subsidiaries
that  currently  are subject to the  provisions  of SFAS 71 will  continue to be
subject to SFAS 71 for the foreseeable future.

As is further  discussed  under the caption  "Regulation  and Rate Matters," the
rate plans previously in effect for KEDNY, KEDLI and Boston Gas Company have all
expired. The continued  application of SFAS 71 to record the activities of these
subsidiaries  is contingent upon the actions of regulators with regard to future
rate  plans.  We filed a base rate case and a  performance  based  rate plan for
Boston Gas  Company on April 16,  2003.  Further,  we are  currently  evaluating
various  options  that may be  available  to us  including,  but not limited to,
proposing new plans for KEDNY and KEDLI.  The ultimate  resolution of any future
rate plans  could have a  significant  impact on the  application  of SFAS 71 to
these  entities  and,  accordingly,   on  our  financial  position,  results  of
operations and cash flows. However, management believes that currently available
facts  support  the  continued  application  of SFAS 71 and that all  regulatory
assets and  liabilities  are  recoverable  or refundable  through the regulatory
environment.

Pension and Other Postretirement Benefits

KeySpan participates in both non-contributory  defined benefit pension plans, as
well   as   other   post-retirement   benefit   ("OPEB")   plans   (collectively
"postretirement plans").  KeySpan's reported costs of providing pension and OPEB
benefits  are  dependent  upon  numerous  factors  resulting  from  actual  plan
experience  and  assumptions  of  future  experience.  Pension  and  OPEB  costs
(collectively   "postretirement   costs")  are   impacted  by  actual   employee
demographics,  the level of  contributions  made to the plans,  earnings on plan
assets,  and health care cost trends.  Changes made to the  provisions  of these
plans may also impact current and future  postretirement  costs.  Postretirement
costs  may  also  be   significantly   affected  by  changes  in  key  actuarial
assumptions,  including  anticipated  rates of  return  on plan  assets  and the
discount  rates  used  in  determining  the  postretirement  costs  and  benefit
obligations.

Historically,  we have funded our pension plans in excess of the amount required
to satisfy  minimum ERISA funding  requirements.  At December 31, 2002, we had a
funding  balance in excess of the ERISA minimum  funding  requirements  and as a
result  KeySpan  will not be  required to make any  contribution  to its pension
plans in 2003. However, although we presently exceed ERISA funding requirements,
our pension plans,  on an actuarial  basis,  are currently  underfunded.  Future
funding  requirements  are heavily  dependent  on actual  return on plan assets.
Therefore,  if the actual  return on plan assets  continues to be  significantly


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<PAGE>

below the expected returns,  we may elect to fund the pension plans in 2003. (In
addition to Item 7 Management's  Discussion and Analysis of Financial  Condition
and Results of  Operations  in KeySpan's  Annual Report on Form 10K for the Year
Ended  December  31,  2002,  see  also  Note 4 of those  Consolidated  Financial
Statements, "Postretirement Benefits.")

Full Cost Accounting

Our gas  exploration  and  production  subsidiaries  use the full cost method to
account for their natural gas and oil  properties.  Under full cost  accounting,
all costs incurred in the acquisition,  exploration,  and development of natural
gas and oil reserves are capitalized into a "full cost pool".  Capitalized costs
include costs of all unproved  properties,  internal costs  directly  related to
natural gas and oil activities, and capitalized interest.

Under full cost  accounting  rules,  total  capitalized  costs are  limited to a
ceiling equal to the present  value of future net  revenues,  discounted at 10%,
plus the lower of cost or fair  value of  unproved  properties  less  income tax
effects (the  "ceiling  limitation").  A quarterly  ceiling test is performed to
evaluate  whether  the net book value of the full cost pool  exceeds the ceiling
limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization)  less deferred  taxes are greater than the  discounted  future net
revenues or ceiling limitation, a write-down or impairment of the full cost pool
is required.

Natural gas and oil reserve quantities represent estimates only. Under full cost
accounting,  reserve  estimates  are used to  determine  the full  cost  ceiling
limitation  as well as the depletion  rate.  Houston  Exploration  estimates its
proved  reserves and future net revenues  using sales prices  estimated to be in
effect as of the date it makes the reserve estimates.  Natural gas prices, which
have fluctuated  widely in recent years,  affect estimated  quantities of proved
reserves and future net revenues.  Any estimates of natural gas and oil reserves
and their values are  inherently  uncertain,  including  many factors beyond our
control.

Valuation of Derivative Instruments

We employ derivative instruments to hedge a portion of our exposure to commodity
price risk and interest rate risk, to partially hedge the cash flow  variability
associated  with our  electric  energy and  capacity  sales from the  Ravenswood
facility, as well as to economically hedge certain other commodity exposures. In
addition, KeySpan Canada has used swap instruments to lock-in the purchase price
on the purchase of electricity  needed to operate its gas processing plants. All
of our derivative instruments,  except for certain weather derivatives, meet the
SFAS 133 definition of a derivative.  Further, none of our currently outstanding
derivatives  qualify  as  "energy  trading  contracts"  as  defined  by  current
accounting literature.

When available, quoted market prices are used to record a contract's fair value.
However,  market  values for  certain  derivative  contracts  may not be readily
available  or  determinable.  A  number  of  our  commodity  related  derivative
instruments are exchange traded and,  accordingly,  fair value  measurements are
generally based on standard New York Mercantile  Exchange  ("NYMEX")  quotes. We
use  industry-published  indices,  NYISO location zone indices, as well as other


                                       52
<PAGE>

local published indices to value contracts for commodities that are not exchange
traded,  such as No. 6 grade  fuel oil and  electricity.  The fair  value of our
electric  capacity hedges is based on published  NYISO capacity  bidding prices.
Further, if no active market exists for a commodity, fair values may be based on
pricing models.  (See Note 6 to the Consolidated  Financial  Statements "Hedging
and  Derivative  Financial  Instruments"  for a further  description  of all our
derivative instruments.)

Regulation and Rate Matters

Gas Matters

As of March 31,  2003,  the rate  agreements  for  KEDNY,  KEDLI and  Boston Gas
Company  have  all  expired.  Under  the  terms  of the  KEDNY  and  KEDLI  rate
agreements,  gas  distribution  rates and all other  provisions  will  remain in
effect until changed by the NYPSC.  At this time,  we are  currently  evaluating
various  options that may be available to us regarding  the KEDNY and KEDLI rate
plans,  including but not limited to,  proposing  new rate plans.  Regarding the
Boston Gas Company, we filed a base rate case and performance based rate plan on
April 16,  2003,  to be  effective  in the fourth  quarter  of 2003.  The filing
requests  an  annual  revenue  increase  of  approximately  $61  million  and  a
performance based rate plan term of five years.

For an additional  discussion of our current gas  distribution  rate agreements,
see KeySpan's  Annual  Report on Form 10K for the Year Ended  December 31, 2002,
Item 7 Management's  Discussion and Analysis of Financial  Condition and Results
of Operations "Regulation and Rate Matters."

Securities and Exchange Commission Regulation

KeySpan and its  subsidiaries  are subject to the  jurisdiction of the SEC under
PUHCA. The rules and regulations under PUHCA generally limit the operations of a
registered  holding company to a single integrated  public utility system,  plus
additional  energy-related  businesses.  In addition,  the principal  regulatory
provisions of PUHCA: (i) regulate certain transactions among affiliates within a
holding company system  including the payment of dividends by such  subsidiaries
to a holding company;  (ii) govern the issuance,  acquisition and disposition of
securities and assets by a holding company and its subsidiaries; (iii) limit the
entry by registered  holding  companies and their  subsidiaries  into businesses
other than electric and/or gas utility businesses; and (iv) require SEC approval
for certain utility mergers and acquisitions.

The SEC's order issued on November 8, 2000, in connection  with our  acquisition
of Eastern  Enterprises and Energy North Inc. as amended on December 6, 2002 and
February 14, 2003, provides us with, among other things, authorization to do the
following through December 31, 2003 (the "Authorization Period"): (a) subject to
an aggregate amount of $5.8 billion, (i) maintain existing financing agreements,
(ii) issue and sell up to $2.2 billion of  additional  securities  in compliance
with certain defined  parameters,  (iii) issue  additional  guarantees and other
forms of credit  support in an  aggregate  amount of $2.0 billion at any time in
addition to any such  securities,  guarantees and credit support  outstanding or
existing as of November 8, 2000, and (iv) amend,  renew,  extend,  supplement or
replace any of the foregoing; (b) issue shares of common stock or reissue shares
of common


                                       53
<PAGE>

stock held in treasury under dividend  reinvestment  and stock-based  management
incentive  and employee  benefit  plans;  (c)  maintain  existing and enter into
additional  hedging  transactions  with respect to outstanding  indebtedness  in
order to manage and minimize  interest rate costs; (d) invest up to $2.2 billion
in  exempt  wholesale  generators;  and (e) pay  dividends  out of  capital  and
unearned   surplus  as  well  as   paid-in-capital   with   respect  to  certain
subsidiaries, subject to certain limitations.


In addition,  we have committed that during the Authorization Period, our common
equity will be at least 30% of our consolidated  capitalization  and each of our
utility  subsidiaries'  common  equity  will be at  least  30% of such  entity's
capitalization.  At March 31, 2003, our consolidated  common equity was 39.5% of
our consolidated  capitalization,  including  commercial  paper, and each of our
utility   subsidiaries  common  equity  was  at  least  35%  of  its  respective
capitalization.

Environmental Matters

KeySpan  is  subject to  various  federal,  state and local laws and  regulatory
programs  related  to  the   environment.   Ongoing   environmental   compliance
activities,  which  have  not  been  material,  are  charged  to  operation  and
maintenance activities.  We estimate that the remaining cost of our manufactured
gas plant ("MGP")  related  environmental  cleanup  activities,  including costs
associated with the Ravenswood  facility,  will be approximately  $188.4 million
and we have recorded a related  liability for such amount. We have also recorded
an additional $38.8 million liability  representing the estimated  environmental
cleanup costs related to a former coal tar processing  facility.  Further, as of
March 31,  2003,  we have  expended a total of $76.1  million  on  environmental
remediation.  (See Note 8 to the Consolidated  Financial Statements,  "Financial
Guarantees and Contingencies".)

Market and Credit Risk Management Activities

Market Risk: We are exposed to market risk arising from potential changes in one
or more market  variables,  such as energy  commodity price risk,  interest rate
risk,  foreign  currency  exchange rate risk,  volumetric risk due to weather or
other  variables.  Such risk includes any or all changes in value whether caused
by commodity positions,  asset ownership,  business or contractual  obligations,
debt covenants,  exposure  concentration,  currency,  weather, and other factors
regardless  of  accounting  method.  We manage our exposure to changes in market
prices using  various  risk  management  techniques  for  non-trading  purposes,
including   hedging   through   the   use  of   derivative   instruments,   both
exchange-traded  and  over-the-counter  contracts,  purchase  of  insurance  and
execution of other  contractual  arrangements.  (See Note 6 to the  Consolidated
Financial  Statements  "Hedging  and  Derivative  Financial  Instruments"  for a
further explanation of derivative financial instruments.)

Credit Risk: We are exposed to credit risk arising from the  potential  that our
counterparties  fail to perform  on their  contractual  obligations.  Our credit
exposures  are  created  primarily  through  the sale of gas and  transportation
services  to  residential,   commercial,  electric  generation,  and  industrial
customers and the provision of retail access  services to gas marketers,  by our
regulated gas  businesses;  the sale of commodities and services to LIPA and the
NYISO;  the sale of gas,  power and  services  to our  retail  customers  by our
unregulated  energy  service  businesses;  entering  into  financial  and energy
derivative contracts with energy marketing companies and financial institutions;
and the sale of gas, natural gas liquids,  oil and processing services to energy
marketing and oil and gas production companies.



                                       54
<PAGE>


We have regional concentration of credit risk due to receivables from
residential, commercial and industrial customers in New York, New Hampshire and
Massachusetts, although this credit risk is spread over a diversified base of
residential, commercial and industrial customers. Customers' payment records are
monitored and action is taken, when appropriate. Companies within the Energy
Services segment have a concentration of credit risk to large customers and to
the governmental and healthcare industries.

We also have concentrations of credit risk from LIPA, our largest customer,  and
from other energy companies.  Concentration of energy company counterparties may
impact  overall  exposure  to  credit  risk in that  our  counterparties  may be
similarly impacted by changes in economic,  regulatory or other  considerations.
We  actively  monitor  the credit  profile of our  wholesale  counterparties  in
derivative and other contractual arrangements,  and manage our level of exposure
accordingly.  Over the past year, the credit quality of certain energy companies
has declined. In instances where  counter-parties'  credit quality has declined,
we may limit our  credit  exposure  by  restricting  new  transactions  with the
counterparty,  requiring additional collateral or credit support and negotiating
the early termination of certain agreements.

Regulatory Issues and Competitive  Environment:  We are subject to various other
risk  exposures  and   uncertainties   associated  with  our  gas  and  electric
operations.  The most significant  contingency involves the evolution of the gas
distribution  and electric  industries  towards more competitive and deregulated
environments.  These risks have not changed  substantially  since  December  31,
2002.  For additional  information  regarding  these risks see KeySpan's  Annual
Report on Form 10K for the Year Ended  December  31, 2002,  Item 7  Management's
Discussion and Analysis of Financial Condition and Results of Operations "Market
and Credit Risk Management Activities".

Cautionary Statement Regarding Forward-Looking Statements

Certain  statements  contained in this  Quarterly  Report on Form 10Q concerning
expectations,  beliefs, plans, objectives,  goals, strategies,  future events or
performance and underlying  assumptions and other statements that are other than
statements of historical  facts,  are  "forward-looking  statements"  within the
meaning of Section  21E of the  Securities  Exchange  Act of 1934,  as  amended.
Without  limiting the  foregoing,  all  statements  under the captions  "Item 2.
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations" and "Item 3.  Quantitative and Qualitative  Disclosures About Market
Risk" relating to our future outlook,  anticipated capital expenditures,  future
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding,  are forward-looking  statements.  Such  forward-looking
statements  reflect  numerous  assumptions  and  involve  a number  of risks and
uncertainties  and actual results may differ  materially from those discussed in
such statements.



                                       55
<PAGE>

Among the factors that could cause actual results to differ materially are:

-    volatility of energy prices of fuel used to generate electricity;

-    fluctuations in weather and in gas and electric prices;

-    general economic conditions, especially in the Northeast United States;

-    our  ability  to  successfully   reduce  our  cost  structure  and  operate
     efficiently;

-    our ability to successfully  contract for natural gas supplies  required to
     meet the needs of our firm customers;

-    implementation of new accounting standards;

-    inflationary trends and interest rates;

-    the ability of KeySpan to identify and make complementary acquisitions,  as
     well as the successful integration of recent and future acquisitions;

-    available sources and cost of fuel;

-    creditworthiness of counter-parties to derivative instruments and commodity
     contracts;

-    retention of key personnel;

-    federal  and  state  regulatory   initiatives  that  increase  competition,
     threaten  cost and  investment  recovery,  and place limits on the type and
     manner in which we invest in new businesses;

-    the impact of federal and state utility  regulatory  policies and orders on
     our regulated and unregulated businesses;

-    potential  write-down  of our  investment  in natural gas  properties  when
     natural  gas  prices  are  depressed  or if we  have  significant  downward
     revisions in our estimated proved gas reserves;

-    competition in general facing our unregulated  Energy Services  businesses,
     including but not limited to competition from other  mechanical,  plumbing,
     heating,  ventilation and air conditioning,  and engineering companies,  as
     well as, other utilities and utility  holding  companies that are permitted
     to engage in such activities;

-    the degree to which we develop  unregulated  business ventures,  as well as
     federal and state regulatory  policies  affecting our ability to retain and
     operate such business ventures profitably;

-    changes in political  conditions,  acts of war or  terrorism;

-    changes in rates of return on overall debt and equity markets could have an
     adverse impact on the value of pension assets;

-    changes in  accounting  standards or GAAP which may require  adjustment  to
     financial statements; and


                                       56
<PAGE>


-    other risks detailed from time to time in other reports and other documents
     filed by KeySpan with the Securities and Exchange Commission ("SEC").

For any of these  statements,  KeySpan  claims the protection of the safe harbor
for forward-looking  information  contained in the Private Securities Litigation
Reform Act of 1995,  as  amended.  For  additional  discussion  on these  risks,
uncertainties and assumptions, see "Item 2. Management's Discussion and Analysis
of Financial  Condition and Results of Operations" and "Item 3. Quantitative and
Qualitative   Disclosures   About  Market  Risk"  contained   herein.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Financially-Settled  Commodity Derivative Instruments: From time to time KeySpan
has utilized  derivative  financial  instruments,  such as futures,  options and
swaps,  for the purpose of hedging exposure to commodity price risk and to hedge
the cash flow  variability  associated  with a portion of peak  electric  energy
sales.

Houston Exploration has utilized collars,  as well as  over-the-counter  ("OTC")
swaps, to hedge the cash flow variability  associated with forecasted sales of a
portion of its natural gas and oil  production.  As of March 31,  2003,  Houston
Exploration has hedged  approximately 67% and 38% of its estimated 2003 and 2004
gas  production,  respectively.  Further,  Houston  Exploration  may enter  into
additional  derivative positions for 2004. Houston Exploration used standard New
York Mercantile  Exchange  ("NYMEX") futures prices and published  volatility in
its Black-Scholes calculation to value its outstanding derivatives.  The maximum
length  of time  over  which  Houston  Exploration  has  hedged  such  cash flow
variability  associated  with: (i) forecasted  natural gas production is through
December  2004;  and (ii)  forecasted  oil  production is through June 2003. The
estimated amount of losses associated with such derivative  instruments that are
reported in Other Comprehensive  Income and that are expected to be reclassified
into  earnings over the next twelve  months is $52.2  million,  or $33.9 million
after-tax.

With respect to price exposure associated with fuel purchases for the Ravenswood
facility,  KeySpan  employs  standard  NYMEX  natural gas futures  contracts and
over-the-counter  financially  settled natural gas basis swaps to hedge the cash
flow  variability of a portion of forecasted  purchases of natural gas.  KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow  variability of a portion of forecasted  purchases of fuel oil that will be
consumed at the  Ravenswood  facility.  The maximum length of time over which we
have hedged cash flow variability  associated with: (i) forecasted  purchases of
natural gas is through October 2003; and (ii)  forecasted  purchases of fuel oil
is through April 2004. We used  standard  NYMEX futures  prices to value the gas
futures contracts and industry published oil indices for number 6 grade fuel oil
to value the oil swap contracts.  The estimated  amount of gains associated with
all such derivative  instruments that are reported in Other Comprehensive Income
and that are  expected to be  reclassified  into  earnings  over the next twelve
months is $3.0 million, or $2.0 million after-tax.


                                       57
<PAGE>


Our retail gas and electric marketing subsidiary,  our domestic gas distribution
operations and KeySpan Canada  employed NYMEX natural gas futures  contracts and
natural gas swaps to lock-in a price for expected  future natural gas purchases.
As applicable,  we used standard  NYMEX futures prices and relevant  natural gas
indices to value the  outstanding  contracts.  The  maximum  length of time over
which we have hedged such cash flow  variability  is through  October 2004.  The
estimated amount of gains  associated with such derivative  instruments that are
reported in Other Comprehensive  Income and that are expected to be reclassified
into  earnings  over the next twelve  months is $3.7  million,  or $2.4  million
after-tax.

We have also engaged in the use of  cash-settled  swap  instruments to hedge the
cash flow variability  associated with (i) a portion of forecasted peak electric
energy sales from the Ravenswood  facility and (ii) forecasted sales of Unforced
Capacity  ("UCAP") to the NYISO.  The maximum  length of time over which we have
hedged cash flow variability is through March 2004. We used  NYISO-location zone
published  indices as well as  published  NYISO  bidding  prices to value  these
outstanding  derivatives.  The estimated  amount of losses  associated with such
derivative  instruments that are reported in Other Comprehensive Income and that
are expected to be  reclassified  into  earnings  over the next twelve months is
$0.9 million, or $0.6 million after-tax.

KeySpan Canada also employs  electricity  swap contracts to lock-in the purchase
price  of  electricity  needed  to  operate  its gas  processing  plants.  These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $1.1 million, or $0.7 million after-tax.

The following  tables set forth selected  financial data  associated  with these
derivative financial  instruments noted above that were outstanding at March 31,
2003.
<TABLE>
<CAPTION>

-----------------------------------------------------------------------------------------------------------------------------
                                     Year of      Volumes                            Fixed          Current         Fair Value
             Type of Contract        Maturity       mmcf     Floor $    Ceiling $    Price $        Price $           ($000)
-----------------------------------------------------------------------------------------------------------------------------
                    Gas
<S>                                   <C>          <C>        <C>        <C>      <C>             <C>               <C>
Collars                                2003         41,250     3.48       4.92               -     5.06 - 5.30       (24,881)
                                       2004         36,600     3.75       5.05               -     4.33 - 5.38       (10,200)

Swaps/Futures - Short Natural Gas      2003         11,214        -          -     3.19 - 3.57     4.22 - 5.30       (21,519)

Swaps/Futures - Long Natural Gas       2003          4,550        -          -     3.14 - 4.92     5.06 - 5.30         6,249
                                       2004             90        -          -     3.49 - 4.35     3.90 - 4.40            31

-----------------------------------------------------------------------------------------------------------------------------
                                                    93,704                                                           (50,320)
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                       58
<PAGE>

<TABLE>
<CAPTION>

----------------------------------------------------------------------------------------------------------------------
                                     Year of      Volumes                                                   Fair Value
      Type of Contract               Maturity     Barrels        Fixed Price $          Current Price $      ($000)
----------------------------------------------------------------------------------------------------------------------
             Oil
<S>                                   <C>        <C>             <C>                     <C>                  <C>
Swaps - Short Fuel Oil                 2003        91,000                 29.70           28.03 - 30.42        (116)

Swaps - Long Fuel Oil                  2003        81,697         20.60 - 23.50           26.41 - 33.58         639
                                       2004         5,548         20.50 - 23.70           25.49 - 26.07          22
----------------------------------------------------------------------------------------------------------------------
                                                  178,245                                                       545
----------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>

--------------------------------------------------------------------------------------------------------------------------------
                            Year of                                       Fixed Margin/                                Fair Value
    Type of Contract        Maturity       Capacity          MWh              Price $           Current Price $          ($000)
--------------------------------------------------------------------------------------------------------------------------------
       Electricity
<S>                          <C>             <C>          <C>             <C>                    <C>                    <C>
Swaps - Energy                2003              -          447,200         30.50 - 61.91          36.02 - 49.52            (647)
                              2004                          99,200                 14.00          23.56 - 32.41          (1,488)

Swaps - Capacity              2003            100                -                  7.75                   7.00              75
--------------------------------------------------------------------------------------------------------------------------------
                                              100          546,400                                                       (2,060)
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>


-------------------------------------------------------------------------------
                                                                         2003
Change in Fair Value of Derivative Instruments                          ($000)
-------------------------------------------------------------------------------
Fair value of contracts at January 1,                                $ (32,628)
Losses on contracts realized                                             3,621
Fair value of new contracts when entered into during period                  -
(Decrease) in fair value of all open contracts                         (22,828)
-------------------------------------------------------------------------------
Fair value of contracts outstanding at March 31,                     $ (51,835)
-------------------------------------------------------------------------------


<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
----------------------------------------------------------------------------------------------------
                                                             Fair Value of Contracts
----------------------------------------------------------------------------------------------------
                                                        Maturity          Maturity           Total
Sources of Fair Value                                     2003              2004           Fair Value
----------------------------------------------------------------------------------------------------
<S>                                                     <C>                <C>             <C>
Prices actively quoted                                 $ (29,898)               31        $ (29,867)
Prices provided by external sources                          417                 -              417
Prices based on models and
    other valuation methods                              (16,423)           (4,424)         (20,847)
Local published indicies                                  (1,538)                -           (1,538)
----------------------------------------------------------------------------------------------------
                                                       $ (47,442)         $ (4,393)       $ (51,835)
----------------------------------------------------------------------------------------------------
</TABLE>


NYMEX  futures  are also used to  economically  hedge the cash flow  variability
associated  with the  purchase  of fuel for a  portion  of our  fleet  vehicles.
Further,  KeySpan  Canada has a  portfolio  of  financially-settled  natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i)  synthetically  fix the price that is paid or received by
KeySpan  Canada for  certain  physical  transactions  involving  natural gas and
natural gas liquids and (ii) transfer the price exposure of such  instruments to
counterparties.  These derivative financial instruments do not qualify for hedge
accounting under SFAS 133. At March 31, 2003,  these  instruments had a net fair
market value of $0.06 million,  which was recorded on the  Consolidated  Balance
Sheet.  Based on the non-hedge  designation of these  instruments,  the gain was
recognized in the Consolidated Statement of Income.


                                       59
<PAGE>


Firm Gas Sales Derivative  Instruments - Regulated Utilities:  We use derivative
financial  instruments to reduce the cash flow  variability  associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution  operations.  Our strategy is to minimize  fluctuations in firm
gas sales prices to our regulated  firm gas sales  customers in our New York and
New  Hampshire  service  territories.  Since these  derivative  instruments  are
employed to reduce the  variability  of the purchase  price of natural gas to be
sold to regulated firm gas sales customers,  the accounting for these derivative
instruments is subject to SFAS 71  "Accounting  for the Effects of Certian Types
of Regulation". Therefore, changes in the market value of these derivatives have
been recorded as a Regulatory Asset or Regulatory  Liability on the Consolidated
Balance  Sheet.  Gains  or  losses  on the  settlement  of these  contracts  are
initially  deferred and then  refunded to or  collected  from our firm gas sales
customers consistent with regulatory requirements.


The following  table sets forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at March 31, 2003.
<TABLE>
<CAPTION>

---------------------------------------------------------------------------------------------------------------------
                                Year of        Volumes                                                     Fair Value
   Type of Contract             Maturity         mmcf      Fixed Price $        Current Price $               ($000)
---------------------------------------------------------------------------------------------------------------------
<S>                             <C>            <C>        <C>                    <C>                         <C>
Options                          2003            1,030     4.01 - 6.00            5.06 - 5.30                    (27)
                                 2004            2,140     5.00 - 6.00            4.54 - 5.38                   (793)
Swaps                            2003           10,470     4.01 - 5.84            5.06 - 5.30                 (2,682)
                                 2004            3,890     4.42 - 5.93            4.41 - 5.38                 (1,337)
---------------------------------------------------------------------------------------------------------------------
                                                17,530                                                        (4,839)
---------------------------------------------------------------------------------------------------------------------
</TABLE>

Physically-Settled  Commodity Derivative Instruments:  Derivative Implementation
Group  ("DIG") Issue C15 and C16 of Statement of Financial  Accounting  Standard
133, "Accounting for Derivative Instruments and Hedging Activities",  as amended
and interpreted,  incorporating SFAS 137 and SFAS 138 and certain implementation
issues  (collectively "SFAS 133") establishes criteria that must be satisfied in
order for  option-type  and forward  contracts in  electricity to be exempted as
normal  purchases and sales,  and relates to the exemption (as normal  purchases
and normal sales) of contracts  that combine a forward  contract and a purchased
option  contract.  Based  upon a  continuing  review of our  physical  commodity
contracts,  we determined  that certain  contracts for the physical  purchase of
natural gas are not exempt as normal  purchases  from the  requirements  of SFAS
133. At March 31, 2003,  the fair value of these  contracts  was a negative $4.9
million.  Since  these  contracts  are for the  purchase  of natural gas sold to
regulated  firm gas sales  customers,  the  accounting  for these  contracts  is
subject to SFAS 71.  Therefore,  changes in the market value of these  contracts
have  been  recorded  as a  Regulatory  Asset  or  Regulatory  Liability  on the
Consolidated Balance Sheet.


                                       60
<PAGE>


Interest  Rate  Derivative  Instruments:  During 2002, we had interest rate swap
agreements  in which  approximately  $1.3  billion  of fixed  rate debt had been
synthetically modified to floating rate debt. Under the terms of the agreements,
we  received  the fixed  coupon  rate  associated  with these bonds and paid the
counter-parties  a variable  interest rate that was reset on a quarterly  basis.
These swaps were  designated as fair-value  hedges and qualified for "short-cut"
hedge accounting treatment under SFAS 133.

In 2002,  we  terminated  two interest  rate swap  agreements  with an aggregate
notional amount of $1.0 billion. The remaining swap, which had a notional amount
of $270.0  million,  was  terminated  on February  25, 2003.  We received  $18.4
million from our swap counterparties as a result of the latter  termination,  of
which $8.1 million represented accrued swap interest. The difference between the
termination settlement amount and the amount of accrued interest, $10.3 million,
was  recorded to earnings  in the first  quarter of 2003.  This swap was used to
hedge a portion of our  outstanding  promissory  notes to LIPA.  As discussed in
Note 5 "Long-Term  Debt", we redeemed a portion of these promissory notes during
the first quarter of 2003.

Additionally,  we had an interest rate swap  agreement that hedged the cash flow
variability  associated  with the forecasted  issuance of a series of commercial
paper offerings. This hedge expired in March 2003.

Weather  Derivatives:  The utility tariffs associated with KEDNE's operations do
not contain weather normalization  adjustments.  As a result,  fluctuations from
normal weather may have a significant positive or negative effect on the results
of these  operations.  To  mitigate  a  substantial  portion  of the  effect  of
fluctuations  from normal weather on our financial  position and cash flows,  we
sold  heating  degree-day  call  options and  purchased  heating-degree  day put
options for the November  2002-March  2003 winter  season.  With respect to sold
call  options,  KeySpan is  required  to make a payment of $40,000  per  heating
degree day to its  counterparties  when actual  weather  experienced  during the
November 2002 - March 2003 time frame was above 4,470 heating degree days, which
equates  to  approximately  1% colder  than  normal  weather.  With  respect  to
purchased put options,  KeySpan  would receive a $20,000 per heating  degree day
payment  from its  counterparties  when actual  weather was below 4,150  heating
degree days, or approximately 7% warmer than normal.  Based on the terms of such
contracts,  we account for such instruments pursuant to the requirements of EITF
99-2,  "Accounting for Weather Derivatives." In this regard, we account for such
instruments  using the  "intrinsic  value method" as set forth in such guidance.
During the first  quarter of 2003,  weather was 10% colder than normal and, as a
result, $11.9 million has been recorded as a reduction to revenues.

Derivative  contracts  are  primarily  used to manage  exposure  to market  risk
arising  from changes in commodity  prices and interest  rates.  In the event of
nonperformance  by a counterparty to a derivative  contract,  the desired impact
may not be  achieved.  The  risk of  counterparty  nonperformance  is  generally
considered  credit risk and is actively  managed by assessing each  counterparty
credit  profile and  negotiating  appropriate  levels of  collateral  and credit
support.


                                       61
<PAGE>


PART II.  OTHER INFORMATION
---------------------------

Item 1. Legal Proceedings

See  Note 8 to  Consolidated  Financial  Statements  "Financial  Guarantees  and
Contingencies" for a discussion of certain legal proceedings.

Item 6.  Exhibits and Reports on Form 8-K

(a)      Exhibits

(b)      Reports on Form 8-K

In our report on Form 8-K dated  January  13,  2003,  we  disclosed  that we had
issued a press release  announcing our proposed issuance of 14,000,000 shares of
common stock.

In our report on Form 8-K dated  January  14,  2003,  we  disclosed  that we had
issued a press release discussing the anticipated net proceeds from the offering
of common stock announced on January 13, 2003.

In our report on Form 8-K dated  January  15,  2003,  we  disclosed  that we had
issued a press release  concerning,  among other things,  our issuance of common
stock.

In our report on Form 8-K dated  January  28,  2003,  we  disclosed  that we had
issued a press release concerning, among other things, our consolidated earnings
for the year ended December 31, 2002.

In our report on Form 8-K dated  February  21, 2003,  we  disclosed  that we had
issued a press  release  concerning,  among other  things,  a proposed sale of a
portion of our ownership interest in The Houston Exploration Company.

In our report on Form 8-K dated April 4, 2003,  we disclosed  that we had issued
$150,000,000  4.650% Notes due 2013 and $150,000,000  5.875% Notes due 2033. The
Notes were issued under the Company's previously filed Registration Statement on
Form S-3 (Reg. No.  333-82230),  which became  effective  February 14, 2002 (the
"Registration Statement"), and the related prospectus supplement, dated April 1,
2003  (the  "Prospectus  Supplement").  The  Notes  were  offered  by  ABN  AMRO
Incorporated,  Salomon Smith Barney Inc.,  The Royal Bank of Scotland plc, Fleet
Securities,  Inc., Scotia Capital (USA) Inc. and Wachovia  Securities,  Inc., as
underwriters.

Exhibits

99.1*Certification  of Chief Executive  Officer  pursuant to 18 U.S.C.  1350, as
     adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.2*Certification  of Chief Financial  Officer  pursuant to 18 U.S.C.  1350, as
     adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

----------------------
*Filed Herewith



                                       62
<PAGE>





                      KEYSPAN CORPORATION AND SUBSIDIARIES
                                    SIGNATURE

Pursuant  to the  requirements  of the  Securities  Exchange  Act of  1934,  the
registrant has duly caused this report to be signed on behalf of the undersigned
there unto duly authorized.

                                                  KEYSPAN CORPORATION
                                                  -------------------
                                                      (Registrant)

Date: May 1, 2003                                  /s/ Gerald Luterman
                                                  --------------------------
                                                  Gerald Luterman
                                                  Executive Vice President and
                                                  Chief Financial Officer



Date: May 1, 2003                                    /s/ Joseph Bodanza
                                                  ---------------------------
                                                  Joseph Bodanza
                                                  Senior Vice President
                                                  and Chief Accounting Officer



Date: May 1, 2003                                    /s/ Theresa Balog
                                                  --------------------------
                                                  Theresa Balog
                                                  Vice President and Controller






                                       63
<PAGE>


CHIEF EXECUTIVE OFFICER'S CERTIFICATION

I, Robert B Catell, certify that:

1. I have reviewed this quarterly report on Form 10-Q of KeySpan Corporation;

2. Based on my  knowledge,  this  quarterly  report  does not contain any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made, not  misleading  with respect to the period covered by this quarterly
report;

3.  Based  on my  knowledge,  the  financial  statements,  and  other  financial
information  included in this quarterly  report,  fairly present in all material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4.  The  registrant's  other  certifying  officer  and  I  are  responsible  for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     a) Designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others  within those  entities,  particularly  during the
period in which this quarterly report is being prepared;

     b) Evaluated the effectiveness of the registrant's  disclosure controls and
procedures  as of a date  within  90  days  prior  to the  filing  date  of this
quarterly report (the "Evaluation Date"); and

     c)  Presented  in  this  quarterly   report  our   conclusions   about  the
effectiveness of the disclosure  controls and procedures based on our evaluation
as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed,  based on our
most recent evaluation,  to the registrant's auditors and the audit committee of
the  registrant's  board of  directors  (or persons  performing  the  equivalent
function):

     a) All  significant  deficiencies  in the design or  operation  of internal
controls  which  could  adversely  affect  the  registrant's  ability to record,
process,  summarize  and  report  financial  data  and have  identified  for the
registrant's auditors any material weaknesses in internal controls; and

     b) Any fraud,  whether or not material,  that involves  management or other
employees who have a significant role in the registrant's internal controls; and



                                       64
<PAGE>




6. The  registrant's  other  certifying  officer  and I have  indicated  in this
quarterly report whether there were significant  changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent  evaluation,  including any corrective  actions with
regard to significant deficiencies and material weaknesses.

Date:    May 1, 2003                       /s/ Robert B. Catell
                                           ------------------------------
                                           Robert B. Catell
                                           Chairman of the Board of Directors
                                           and Chief Executive Officer




















                                       65
<PAGE>



CHIEF FINANCIAL OFFICER'S CERTIFICATION

I, Gerald Luterman, certify that:

1. I have reviewed this quarterly report on Form 10-Q of KeySpan Corporation;

2. Based on my  knowledge,  this  quarterly  report  does not contain any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made, not  misleading  with respect to the period covered by this quarterly
report;

3.  Based  on my  knowledge,  the  financial  statements,  and  other  financial
information  included in this quarterly  report,  fairly present in all material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4.  The  registrant's  other  certifying  officer  and  I  are  responsible  for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     a) Designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others  within those  entities,  particularly  during the
period in which this quarterly report is being prepared;

     b) Evaluated the effectiveness of the registrant's  disclosure controls and
procedures  as of a date  within  90  days  prior  to the  filing  date  of this
quarterly report (the "Evaluation Date"); and

     c)  Presented  in  this  quarterly   report  our   conclusions   about  the
effectiveness of the disclosure  controls and procedures based on our evaluation
as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed,  based on our
most recent evaluation,  to the registrant's auditors and the audit committee of
the  registrant's  board of  directors  (or persons  performing  the  equivalent
function):

     a) All  significant  deficiencies  in the design or  operation  of internal
controls  which  could  adversely  affect  the  registrant's  ability to record,
process,  summarize  and  report  financial  data  and have  identified  for the
registrant's auditors any material weaknesses in internal controls; and

     b) Any fraud,  whether or not material,  that involves  management or other
employees who have a significant role in the registrant's internal controls; and



                                       66
<PAGE>




6. The  registrant's  other  certifying  officer  and I have  indicated  in this
quarterly report whether there were significant  changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent  evaluation,  including any corrective  actions with
regard to significant deficiencies and material weaknesses.

Date:    May 1, 2003                               /s/ Gerald Luterman
                                                   ---------------------
                                                   Gerald Luterman
                                                   Executive Vice President
                                                   and Chief Financial Officer























                                       67