3



                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D. C. 20549
                                    Form 10-Q
(Mark One)
 X  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
--- ACT OF 1934


For the quarterly period ended                June 30, 2002
                               -------------------------------------------------
                                       OR
    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             (I.R.S. 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)

(Former name, former address and former fiscal year, if changed since last
 report)

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No

                      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 July 31, 2002
---------------------------                        -----------------------------
      $.01 par value                                        141,407,660

<PAGE>

                      KEYSPAN CORPORATION AND SUBSIDIARIES

                                      INDEX

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

Item 1. Financial Statements

            Consolidated Balance Sheet -
            June 30, 2002 and December 31, 2001                            3

            Consolidated Statement of Income -
            Three and Six Months Ended June 30, 2002 and 2001
                                                                           5

            Consolidated Statement of Cash Flows -
            Six Months Ended June 30, 2002 and 2001                        6

            Notes to Consolidated Financial Statements                     7

Item 2. Management's Discussion and Analysis of Financial
            Condition and Results of Operations                           26

Item 3. Quantitative and Qualitative Disclosures
            About Market Risk                                             52

                           Part II. OTHER INFORMATION

Item 1. Legal Proceedings                                                 58

Item 4. Submission of Matters to a Vote of Security Holders               59

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

Signatures                                                                61



<PAGE>


<TABLE>
<CAPTION>

                           CONSOLIDATED BALANCE SHEET
                                   (Unaudited)
                            (In Thousands of Dollars)

-------------------------------------------------------------------------------------------------------------------------------

                                                                   June 30, 2002                      December 31, 2001
                                                          --------------------------------     --------------------------------


ASSETS
<S>                                                                          <C>                                  <C>
Current Assets
    Cash and cash equivalents                        $                            137,599   $                          159,252
    Accounts receivable                                                         1,236,016                            1,344,898
    Allowance for uncollectible accounts                                         (88,432)                             (72,299)
    Gas in storage, at average cost                                               239,403                              334,999
    Materials and supplies, at average cost                                       106,652                              105,693
    Other                                                                         220,320                              125,944
                                                          --------------------------------     --------------------------------
                                                                                1,851,558                            1,998,487
                                                          --------------------------------     --------------------------------

Net Assets Held for Disposal                                                      190,135                              191,055
                                                          --------------------------------     --------------------------------
Equity Investments and Other                                                      241,342                              223,249
                                                          --------------------------------     --------------------------------

Property
    Gas                                                                         5,877,621                            5,704,857
    Electric                                                                    1,840,067                            1,629,768
    Other                                                                         418,675                              400,643
    Accumulated depreciation                                                  (2,647,591)                          (2,533,466)
    Gas exploration and production, at cost                                     2,348,391                            2,200,851
    Accumulated depletion                                                       (882,721)                            (796,722)
                                                          --------------------------------     --------------------------------
                                                                                6,954,442                            6,605,931
                                                          --------------------------------     --------------------------------

Deferred Charges
    Regulatory assets                                                             429,077                              458,191
    Goodwill, net of amortization                                               1,786,561                            1,782,826
    Other                                                                         496,415                              529,867
                                                          --------------------------------     --------------------------------
                                                                                2,712,053                            2,770,884
                                                          --------------------------------     --------------------------------

Total Assets                                         $                         11,949,530   $                       11,789,606
                                                          ================================     ================================
</TABLE>



        See accompanying Notes to the Consolidated Financial Statements.


<PAGE>










<TABLE>
<CAPTION>
                           CONSOLIDATED BALANCE SHEET
                                   (Unaudited)
                            (In Thousands of Dollars)

----------------------------------------------------------------------------------------------------------------------------------

                                                                       June 30, 2002                      December 31, 2001
                                                              --------------------------------      ------------------------------

LIABILITIES AND CAPITALIZATION
<S>                                                                               <C>                                <C>
Current Liabilities

    Current redemption of long term debt                $                               1,480  $                              993
    Accounts payable and accrued expenses                                           1,006,073                           1,091,430
    Commercial paper                                                                  570,655                           1,048,450
    Dividends payable                                                                  64,273                              63,442
    Taxes accrued                                                                      11,068                              50,281
    Customer deposits                                                                  36,402                              36,151
    Interest accrued                                                                   85,169                              93,962
                                                              --------------------------------      ------------------------------
                                                                                    1,775,120                           2,384,709
                                                              --------------------------------      ------------------------------



Deferred Credits and Other Liabilities
    Regulatory liabilities                                                             68,790                              39,442
    Deferred income tax                                                               811,349                             598,072
    Postretirement benefits and other reserves                                        708,320                             694,680
    Other                                                                             149,857                             207,992
                                                              --------------------------------      ------------------------------
                                                                                    1,738,316                           1,540,186
                                                              --------------------------------      ------------------------------



Capitalization

    Common stock, $.01 par value, authorized 450,000,000
    shares; outstanding 140,570,579 and                                             2,995,501                           2,995,797
    137,251,386 shares stated at

    Retained earnings                                                                 498,751                             452,206
    Other comprehensive income                                                        (27,997)                              4,483
    Treasury stock purchased                                                         (509,988)                            (561,884)
                                                               --------------------------------      ------------------------------
      Total common shareholders equity                                               2,956,267                          2,890,602
    Preferred stock                                                                     84,077                             84,077
    Long-term debt                                                                   5,192,217                          4,697,649
                                                               --------------------------------      ------------------------------
Total Capitalization                                                                 8,232,561                          7,672,328
                                                               --------------------------------      ------------------------------

Minority Interest in Subsidiary Companies                                              203,533                            192,383
                                                               --------------------------------      ------------------------------
Total Liabilities and Capitalization                           $                    11,949,530  $                      11,789,606
                                                               ================================      ==============================
</TABLE>

         See accompanying Notes to the Consolidated Financial Statements

<PAGE>

<TABLE>

                        CONSOLIDATED STATEMENT OF INCOME
                                   (Unaudited)
               (In Thousands of Dollars, Except Per Share Amounts)
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                              Three Months         Three Months        Six Months        Six Months
                                                                  Ended               Ended              Ended              Ended
                                                               June 30, 2002      June 30, 2001      June 30, 2002     June 30, 2001
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                         <C>                 <C>                <C>                 <C>
Revenues
     Gas Distribution                                     $    521,822         $    620,685     $    1,744,791       $   2,374,329
     Electric Services                                         354,756              357,904            669,440             701,275
     Energy Services                                           229,311              232,771            470,870             551,864
     Gas Exploration                                            88,274              103,720            162,988             235,731
     Energy Investments                                         21,942               24,222             39,575              51,191
                                                     ------------------ -------------------- ------------------  ------------------
     Total Revenues                                          1,216,105            1,339,302          3,087,664           3,914,390
                                                     ------------------ -------------------- ------------------  ------------------
Operating Expenses
     Purchased gas for resale                                  249,942              348,349            899,299           1,545,698
     Fuel and purchased power                                   93,292              146,357            177,664             289,657
     Operations and maintenance                                548,094              533,803          1,041,660           1,037,686
     Depreciation, depletion and amortization                  127,463              121,578            253,460             252,742
     Operating taxes                                            87,388              100,835            207,781             242,825
                                                     ------------------ -------------------- ------------------  ------------------
     Total Operating Expenses                                1,106,179            1,250,922          2,579,864           3,368,608
                                                     ------------------ -------------------- ------------------  ------------------
Operating Income                                               109,926               88,380            507,800             545,782
                                                     ------------------ -------------------- ------------------  ------------------
Other Income and (Deductions)
     Minority interest                                          (6,138)            (11,869)            (10,569)            (27,280)
     Other income                                                8,484               8,713              21,102              28,826
                                                     ------------------ -------------------- ------------------  ------------------
     Total Other Income                                          2,346              (3,156)             10,533               1,546
                                                     ------------------ -------------------- ------------------  ------------------
Income Before Interest Charges                                 112,272              85,224             518,333             547,328
     and Income Taxes                                ------------------ -------------------- ------------------  ------------------
Interest Charges                                                70,054              91,927             142,661             185,230
                                                     ------------------ -------------------- ------------------  ------------------
Income Taxes
     Current                                                     5,587             (24,825)            (78,031)             88,574
     Deferred                                                    7,457              28,539             209,898              59,827
                                                     ------------------ -------------------- ------------------  ------------------
     Total Income Taxes                                         13,044               3,714             131,867             148,401
                                                     ------------------ -------------------- ------------------  ------------------
Preferred stock dividend requirements                            1,476               1,476               2,952               2,952
                                                     ------------------ -------------------- ------------------  ------------------
Earnings (Loss) from Continuing Operations                      27,698             (11,893)            240,853             210,745
                                                     ------------------ -------------------- ------------------  ------------------
Discontinued Operations
    Income from operations, net of tax                               -               3,892                   -               4,553
    Loss on Disposal, net of tax of $13,050                    (19,662)                  -             (19,662)                  -
                                                     ------------------ -------------------- ------------------  ------------------
Loss from Discontinued Operations                              (19,662)              3,892             (19,662)              4,553
                                                     ------------------ -------------------- ------------------  ------------------
Earnings (Loss) for Common Stock                           $     8,036         $    (8,001)      $     221,191        $    215,298
                                                     ================== ==================== ==================  ==================
Basic Earnings (Loss) Per Share from
     Continuing Operations                                        0.20               (0.09)               1.71                1.54
Basic Earnings (Loss) Per Share from
     Discontinued Operations                                     (0.14)               0.03               (0.14)               0.03
                                                     ------------------ -------------------- ------------------  ------------------
Basic Earnings (Loss) Per Share                            $      0.06         $     (0.06)       $       1.57        $       1.57
                                                     ================== ==================== ==================  ==================
Diluted Earnings (Loss) Per Share from
     Continuing Operations                                        0.20               (0.09)               1.70                1.52

Diluted Earnings (Loss) Per Share from
     Discontinued Operations                                     (0.14)                0.03              (0.14)               0.03
                                                     ================== ==================== ==================  ==================
Diluted Earnings (Loss) Per Share                          $      0.06         $      (0.06)       $      1.56         $      1.55
                                                     ================== ==================== ==================  ==================
Average Common Shares Outstanding (000)                        141,063              137,916            140,551             137,438
Average Common Shares Outstanding Diluted (000)                142,156              139,361            141,706             138,872

</TABLE>

See accompanying Notes to the Consolidated Financial Statements.

<PAGE>


<TABLE>
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                                   (Unaudited)
                            (In Thousands of Dollars)
<CAPTION>

------------------------------------------------------------------------------------------------------------------------------------

                                                                               Six Months                            Six Months
                                                                                 Ended                                 Ended
                                                                             June 30, 2002                         June 30, 2001
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>                                  <C>
Operating Activities

Earnings from continuing operations                             $                     243,805                 $            213,697
Adjustments to reconcile net income to  net cash
    Depreciation, depletion and amortization                                          253,460                              252,742
    Deferred income tax                                                                26,741*                              59,827
    Income from equity investments                                                     (7,409)                              (6,294)
    Dividends from equity investments                                                     120                                    -
    Provision for loss on contracting business                                              -                               28,012

Changes in assets and liabilities
    Accounts receivable                                                               125,015                              321,673
    Materials and supplies, fuel oil and gas in storage                                94,637                               24,518
    Accounts payable and accrued expenses                                             (48,213)                            (425,263)
    Interest accrued                                                                   (8,793)                              52,252
    Other                                                                               4,394*                              33,706
                                                                  ----------------------------     --------------------------------
Net Cash Provided by Operating Activities                                             683,757                              554,870
                                                                  ----------------------------     --------------------------------

Investing Activities
Capital expenditures                                                                 (595,503)                            (424,807)
Proceeds from sale of assets                                                                -                               18,458
Other                                                                                       -                               (7,822)
                                                                  ----------------------------     --------------------------------
Net Cash Used in Investing Activities                                                (595,503)                            (414,171)
                                                                  ----------------------------     --------------------------------
Financing Activities
Issuance of treasury stock                                                             51,896                               64,107
Issuance of long-term debt                                                            507,754                              708,000
Payment of long-term debt                                                             (54,590)                            (152,000)
Payment of commercial paper                                                          (477,795)                            (497,033)
Preferred stock dividends paid                                                         (2,952)                              (2,952)
Common stock dividends paid                                                          (124,684)                            (121,937)
Other                                                                                  (9,536)                                5,102
                                                                  ----------------------------     --------------------------------
Net Cash (Used in) Provided By Financing Activities                                  (109,907)                                3,287
                                                                  ----------------------------     --------------------------------
Net (decrease) increase  in Cash  and Cash Equivalents          $                     (21,653)   $                          143,986
                                                                  ============================     ================================
Cash and cash equivalents at beginning of period                $                     159,252    $                           83,329
Net (decrease) increase  in cash and cash equivalents                                 (21,653)                              143,986
                                                                  ----------------------------     --------------------------------
Cash and Cash Equivalents at End of Period                      $                     137,599    $                         227,315
                                                                  ============================     ================================
</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.

*Includes  a non-cash  reduction  to  current  taxes  payable of $183.2  million
resulting  from the  finalization  of  certain  tax issues  associated  with the
KeySpan/Long Island Lighting Company merger.

        See accompanying Notes to the Consolidated Financial Statements.

<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"). We operate six
regulated  utilities that distribute  natural gas to  approximately  2.5 million
customers in New York City, Long Island, Massachusetts and New Hampshire, making
us 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. 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").  Our
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 installation and 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,
electric  generation,  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 our financial position as of
June 30, 2002,  and the results of our  operations  for the three and six months
ended June 30, 2002 and June 30, 2001,  as well as cash flows for the six months
ended June 30, 2002 and June 30, 2001.  The  accompanying  financial  statements
should be read in conjunction  with the  consolidated  financial  statements and
notes included in our Annual Report on Form 10-K for the year ended December 31,
2001,  as amended,  as well as our March 31,  2002 10Q.  The  December  31, 2001
financial statement information has been derived from the 2001 audited financial
statements. Income from interim periods may not be indicative of future results.

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.


<PAGE>


We have approximately 2.1 million options outstanding at June 30,2002 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. Further, we have 84,077 shares of convertible preferred stock
outstanding that can be converted into 244,104 shares of common stock. These
shares were not in the calculation of diluted EPS for the three months ended
June 30, 2002 since to do so would have been anti-dilutive.

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>

                                                               (In Thousands of Dollars, Except Per Share)
------------------------------------------------------------- ------------------- --------------------------------------------------
                                                             Three Months Ended Three Months Ended Six Months Ended Six Months Ended
                                                               June 30, 2002       June 30, 2001    June 30, 2002     June 30, 2001
------------------------------------------------------------- ------------------ ---------------- --------------- --------------
<S>                                                                    <C>            <C>              <C>            <C>
Earnings (loss) from Continuing Operations                            $  27,698      $  (11,893)      $ 240,853     $  210,745
   Interest savings on convertible preferred stock                            -             142             284            284
   Houston Exploration dilution (options)                                  (129)           (310)           (225)          (859)
------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Earnings (loss) for common stock - adjusted                              27,569         (12,061)        240,912        210,170
------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Weighted average shares outstanding (000)                               141,063         137,916         140,551        137,438

Add dilutive securities:
    Options                                                               1,093           1,201             911          1,190
    Convertible preferred stock                                               -             244             244            244
------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Total weighted average shares outstanding - assuming dilution           142,156         139,361         141,706        138,872
------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Basic Earnings (Loss) Per Share from Continuing Operations            $    0.20      $    (0.09)        $  1.71       $   1.54
------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Diluted Earnings (Loss) Per Share from Continuing Operations          $    0.20      $    (0.09)        $  1.70       $   1.52
------------------------------------------------------------- ------------------ ---------------- --------------- --------------
</TABLE>

2.  BUSINESS SEGMENTS

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

The Gas Distribution segment consists of our six regulated 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.


<PAGE>


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 six to twelve years.
The Electric  Services  segment also includes  subsidiaries  that own, lease and
operate the 2,200 megawatt Ravenswood electric generation facility  ("Ravenswood
facility"), located in Queens, New York. We sell all of the energy, capacity and
ancillary  services  related  to  the  Ravenswood   facility  to  the  New  York
Independent  System  Operator  ("NYISO")  energy markets.  Further,  we recently
placed two 79 megawatt generating facilities into service, (one in June 2002 and
the other in July 2002) located on Long Island.  Currently, our primary electric
generation  customers are LIPA and the NYISO energy markets. The capacity of and
energy from these facilities are dedicated to LIPA under 25 year contracts.

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
natural gas and electricity to residential and small commercial customers;  (ii)
Business  Solutions,  which provides  mechanical  contracting,  engineering  and
consulting   services  to  commercial   and  industrial   customers,   including
installation of plumbing,  heating,  ventilation and air conditioning equipment;
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 67%
equity  interest in The Houston  Exploration  Company  ("Houston  Exploration" -
NYSE: THX), 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.

Subsidiaries in this segment 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.

The  accounting  policies  of the  segments  are the same as those  used for the
preparation of the Consolidated Financial Statements. Our 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 earnings  before interest and taxes ("EBIT") basis. At June 30,
2002, the total assets of each  reportable  segment have not changed  materially
from  December  31,  2001.  To  reflect  a  complete  picture  of  our  electric
operations,  we reclassified,  for all periods presented,  KeySpan Energy Supply
from  the  Energy  Services  segment  to the  Electric  Services  segment.  This
subsidiary  provides  management  and  procurement  services for fuel supply and
management of energy sales,  primarily for and from the Ravenswood facility. Due
to the July 2002 sale of Midland  Enterprises  LLC, our marine  barge  business,
this  subsidiary is reported as  discontinued  operations in 2002 and 2001.  The
reportable segment information,  excluding Midland, is as follows:

<PAGE>

<TABLE>
<CAPTION>
                                                              ( In Thousands of Dollars)
------------------------------------------------------------------------------------------------------------------------------------

                                                                             Energy Investments
                                                                    -------------------------------
                               Gas        Electric        Energy      Gas Exploration      Other
                          Distribution    Services       Services      and Production   Investments   Eliminations      Consolidated
------------------------- --------------- ------------ ------------ ------------------ ------------- --------------- ---------------
<S>                             <C>          <C>         <C>                 <C>           <C>             <C>           <C>
Three Months Ended
June 30, 2002

Unaffiliated Revenue             521,822      354,756      229,311             88,274        21,942               -       1,216,105

Intersegment Revenue                   -           25            -                  -             -             (25)              -

Earnings Before Interest
  and Taxes                       29,243       64,719      (10,252)            23,595         1,266           3,701         112,272


Three Months Ended
June 30, 2001

Unaffiliated Revenue             620,685      357,904      232,771            103,720        24,222               -       1,339,302

Intersegment Revenue                   -           25            -                  -             -             (25)              -

Earnings Before Interest
  and Taxes                       18,924       67,725      (57,040)            43,957         7,148           4,510          85,224
------------------------- --------------- ------------ ------------ ------------------ ------------- --------------- ---------------
</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 $354.8 million and $357.9 million for the three
months ended June 30, 2002 and 2001 represent  approximately  29% and 27% of our
consolidated revenues, respectively.
<TABLE>
<CAPTION>
                                                                                                          (In Thousands of Dollars)
------------------------------------------------------------------------------------------------------------------------------------

                                                                           Energy Investments
                                                                    ----------------------------

                                Gas        Electric       Energy    Gas Exploration     Other
                           Distribution    Services      Services    and Production  Investments     Eliminations     Consolidated
------------------------- ---------------- ------------ ----------- --------------- ------------- ----------------- ----------------
<S>                            <C>           <C>         <C>              <C>           <C>               <C>             <C>
Six Months Ended
June 30, 2002

Unaffiliated Revenue            1,744,791      669,440     470,870          162,988       39,575                 -         3,087,664

Intersegment Revenue                    -           49           -                -            -               (49)                -

Earnings Before Interest
  and Taxes                       358,899      130,364     (19,449)          39,267        6,159             3,093           518,333


Six Months Ended
June 30, 2001

Unaffiliated Revenue            2,374,329      701,275    551,864           235,731       51,191                 -         3,914,390

Intersegment Revenue                    -           50          -                 -            -               (50)                -

Earnings Before Interest
  and Taxes                       349,605      133,306    (63,419)          109,473       16,401             1,962           547,328
------------------------- ---------------- ------------ ---------- ---------------- ------------- ----------------- ----------------
</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 $669.4  million and $701.3 million for the six
months ended June 30, 2002 and 2001 represent  approximately  22% and 18% of our
consolidated revenues, respectively.

<PAGE>

3. COMPREHENSIVE INCOME

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

                                                                                                (In Thousands of Dollars)
------------------------------------------------------ ----------------------------------------------------------- -----------------
                                                       Three Months Ended Three Months Ended   Six Months Ended     Six Months Ended
                                                         June 30, 2002       June 30, 2001      June 30, 2002         June 30, 2001
------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
<S>                                                              <C>            <C>               <C>                  <C>
Earnings (Loss) for Common Stock                                $  8,036        $ (8,001)        $  221,191           $  215,298
------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
Other comprehensive income (loss), net of tax

    Reclassification adjustment for gains
       realized in net income                                    (2,998)            (212)          (10,285)              (3,454)

    Foreign currency translation adjustments                      10,829            1,554             9,116              (8,128)

    Unrealized losses on marketable securities                   (3,195)          (4,765)           (4,236)              (2,148)

    Accrued unfunded pension obligation                                -                -           (1,132)                    -

    Unrealized (losses) gains on derivative financial
      instruments                                                (2,159)           20,124          (25,944)               21,075
------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
Other comprehensive income (loss)                                  2,477           16,701          (32,481)                7,345
------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
Comprehensive income                                           $  10,513         $  8,700        $  188,710           $  222,643
------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
Related tax expense (benefit)
     Reclassification adjustment for gains
       realized in net income                                     (1,614)            (114)           (5,538)              (1,860)

     Foreign currency translation adjustments                       5,831              837             4,908              (4,376)

     Unrealized losses on marketable securities                   (1,721)          (2,566)           (2,281)              (1,157)

     Accrued unfunded pension obligation                                -                -             (610)                    -

     Unrealized (losses) gains on derivative financial
       instruments                                                (1,163)           10,836          (13,970)               11,348
-------------------------------------------------------- ----------------- ----------------- ----------------- --------------------
Total tax expense (benefit)                                     $   1,333         $  8,993        $ (17,491)             $  3,955
-------------------------------------------------------- ----------------- ----------------- ----------------- --------------------
</TABLE>



4.  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 us, were associated with our
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 we purchased  the  Ravenswood  facility  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.

<PAGE>

We presently estimate the remaining  environmental  cleanup costs related to our
New York MGP sites will be $150.3  million,  which amount has been accrued by us
as a reasonable estimate of probable cost for known sites. Expenditures incurred
to date by us with respect to these MGP-related sites total $41.0 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. At
June 30, 2002, we have  reflected a regulatory  asset of $123.9  million for our
New York/Long Island MGP sites.

We are  also  responsible  for  environmental  obligations  associated  with the
Ravenswood  electric generating  facility.  The extent of our liability does not
include  liabilities  arising from the  disposal of waste at off-site  locations
prior to the  acquisition  and any  monetary  fines  arising  from  Consolidated
Edison's  pre-closing  conduct.  Based on  information  currently  available for
environmental  contingencies related to the Ravenswood facility acquisition,  we
have accrued a $5.0 million liability.

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 or their predecessor  companies.
Boston Gas Company, Colonial Gas Company and Essex Gas Company may have or share
responsibility under applicable environmental laws for the remediation of 66 MPG
sites and  related  facilities,  and  EnergyNorth  Natural Gas may have or share
responsibility under applicable environmental laws for the remediation of 10 MGP
sites and related facilities.

We  presently   estimate  the   remaining   cost  of  New  England   MGP-related
environmental  cleanup  activities will be $51.7 million,  which amount has been
accrued  by us as a  reasonable  estimate  of  probable  cost for  known  sites.
Expenditures  incurred since November 8, 2000 with respect to these  MGP-related
activities total $11.5 million.

The  Massachusetts  Department  of  Telecommunications  and  Energy  and the New
Hampshire Public  Utilities  Commission have issued rate orders that provide for
the recovery of site investigation and remediation costs in rates charged to gas
distribution  customers.  Accordingly,  at June 30,  2002,  we have  reflected a
regulatory asset of $60.0 million for the KEDNE MGP sites.  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.

<PAGE>

KeySpan  New  England  LLC  Sites.  We are  aware  of  three  non-utility  sites
associated with the historic operations of KeySpan New England, LLC, a 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 former Everett Coal Tar  Processing  Facility (the
"Everett Facility") located in Massachusetts.  Honeywell International, Inc. and
Beazer East,  Inc.  (both former owners and  operators of the Everett  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 site.

We presently estimate the remaining cost of our environmental cleanup activities
for the three  non-utility  sites will be  approximately  $41.8  million,  which
amount has been accrued by us a reasonable  estimate of probable costs for known
sites.  Expenditures incurred since November 8, 2000 with respect to these sites
total  $1.5  million.  Additionally,  see Note 10 "Legal  Matters"  for  further
information on New England environmental matters.

We believe that in the aggregate,  the accrued  liability for  investigation and
remediation  of the New  York  and New  England  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 our Annual  Report on Form 10-K for the year ended  December 31, 2001 Note 8
to  those  Consolidated  Financial  Statements   "Contractual   Obligations  and
Contingencies" for further information on environmental matters.

5. LONG-TERM DEBT

At December 31, 2001, we had an existing $1 billion shelf registration statement
on file with the Securities and Exchange Commission  ("SEC"),  with $500 million
available for issuance.  In February 2002, we updated our shelf registration for
the issuance of an additional $1.2 billion of securities,  thereby giving us the
ability  to issue  up to $1.7  billion  of  debt,  equity  or  various  forms of
preferred  stock. At December 31, 2001, we had authority under PUHCA to issue up
to $1 billion of this amount.

<PAGE>

On April  30,  2002,  we  issued  $460  million  of MEDS  Equity  Units at 8.75%
consisting of a three-year  forward purchase contract for our common stock and a
six-year  note. The purchase  contract  commits us, three years from the date of
issuance of the MEDS Equity  Units,  to issue and the  investors to purchase,  a
number of shares of our common stock based on a formula tied to the market price
of our common  stock at that time.  The 8.75%  coupon is  composed  of  interest
payments on the  six-year  note of 4.9% and premium  payments on the  three-year
equity  forward  contract  of 3.85%.  These  instruments  have been  recorded as
long-term debt on our Consolidated Balance Sheet.  Further, upon issuance of the
MEDS Equity  Units,  we recorded a direct  charge to Retained  Earnings of $49.1
million,  which represents the present value of the forward  contract's  premium
payments.

The issuance of the MEDS equity  units  utilized  $920 million of our  financing
authority under both the shelf  registration and our PUHCA financing  authority.
Both the $460 million six-year note and the $460 million forward equity contract
are considered current issuances under these  arrangements.  Therefore,  we have
$780 million available for issuance under the shelf registration and $80 million
available under PUHCA  authorization.  We have filed an application with the SEC
under  PUHCA to  increase  our  financing  authority  by $700  million,  thereby
matching  our  shelf  availability.  We  anticipate  action  by the  SEC on this
application this year.

These  securities  are  currently not  considered  convertible  instruments  for
purposes of applying SFAS 128 "Earnings Per Share" calculations, unless or until
such  time  as the  market  value  of  our  common  stock  reaches  a  threshold
appreciation price which will be higher than our current per share market value.
Interest payments will, however, reduce net income and earnings per share.

The Emerging  Issues Task Force of the Financial  Accounting  Standards Board is
considering proposals related to accounting for certain securities and financial
instruments,  including  securities  such  as  the  Equity  Units.  The  current
proposals being  considered  include the method of accounting  discussed  above.
Alternatively,  other  proposals  being  considered  could  result in the common
shares issuable pursuant to the purchase  contract to be deemed  outstanding and
included in the calculation of diluted  earnings per share,  and could result in
periodic "marking to market" of the purchase contracts, causing periodic charges
or credits to income. If this latter approach were adopted, our diluted earnings
per share could  increase  and  decrease  from quarter to quarter to reflect the
lesser and greater number of shares issuable upon satisfaction of the contract.

In May 2002, Colonial Gas Company repaid $15 million of its 6.81% Series A First
Mortgage Medium -Term Notes. These Notes would have matured on May 19, 2027, but
the  holder of the Notes  elected  to  exercise a put option to redeem the Notes
early.

6. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity  Contracts and Electric Derivative  Instruments:  From time to time we
have 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 our peak electric energy
sales.  Our  hedging  objectives  and  strategies  have  remained  substantially
unchanged from year-end.

<PAGE>

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 production.  As of June 30, 2002, Houston Exploration
has  hedged  approximately  64% of its  estimated  2002  yearly  production  and
approximately  40% of its estimated  2003 yearly  production.  Further,  Houston
Exploration  may enter into additional  derivative  positions for 2003 and 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 is through December 2003. The
estimated amount of gains or losses associated with such derivative  instruments
that  are  reported  in  accumulated  other  comprehensive  income  and that are
expected to be  reclassified  into  earnings over the next twelve months is $3.8
million. The measured amount of hedge ineffectiveness was immaterial.

We have also employed standard NYMEX gas futures contracts,  as well as oil swap
derivative  contracts,  to fix the purchase price for a portion of the fuel used
at the Ravenswood facility. The maximum length of time over which we have hedged
such cash flow  variability  is through  February  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 or losses associated with such derivative  instruments
that  are  reported  in  accumulated  other  comprehensive  income  and that are
expected to be  reclassified  into  earnings over the next twelve months is $1.7
million. The measured amount of hedge ineffectiveness was immaterial.

Our gas  and  electric  marketing  subsidiary,  as well as our gas  distribution
operations,  have fixed rate gas sales  contracts  and utilized  standard  NYMEX
futures  contracts to lock-in a price for future natural gas purchases.  We used
standard NYMEX futures prices to value the  outstanding  contracts.  The maximum
length of time over which we have hedged such cash flow  variability  is through
February  2003.  The estimated  amount of gains or losses  associated  with such
derivative  instruments  that are reported in  accumulated  other  comprehensive
income and that are  expected to be  reclassified  into  earnings  over the next
twelve months is $0.8 million. The measured amount of hedge  ineffectiveness was
immaterial.

We have also engaged in the use of derivative swap instruments to hedge the cash
flow  variability  associated  with a portion of our forecasted  2002 summer and
winter peak electric  energy sales from the  Ravenswood  facility.  We currently
have hedge  positions for  approximately  50% of our estimated  2002 summer peak
electric  sales  from  the  Ravenswood  facility.  We used  NYISO-location  zone
published   indices  and  standard  NYMEX  prices  to  value  these  outstanding
derivatives. The maximum length of time over which we have hedged such cash flow
variability is through  December  2002. The estimated  amount of gains or losses
associated  with such  derivative  instruments  that are reported in accumulated
other  comprehensive  income  and  that are  expected  to be  reclassified  into
earnings  over the next twelve months is $1.6  million.  The measured  amount of
hedge ineffectiveness was immaterial.

<PAGE>

KeySpan Canada has also employed electric swap contracts to lock-in the purchase
price on the  purchase  of  electricity  needed to  operate  its gas  processing
plants.  These  contracts are not exchange-  traded and we used local  published
indices 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 gains  or  losses  associated  with  such  derivative
instruments that are reported in accumulated other comprehensive income and that
are expected to be  reclassified  into earnings over the next twelve months is a
loss  of  $2.2  million.  The  measured  amount  of  hedge  ineffectiveness  was
immaterial.

The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at June 30,
2002.
<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------------------------------------------

                               Year of       Volumes                                Fixed Price $    Current Price $     Fair Value
          Type of Contract    Maturity        mmcf        Floor $     Ceiling $                                            ($000)
----------------------------- ---------- ------------- ------------ ------------- ----------------- ----------------- --------------

                Gas
<S>                            <C>          <C>           <C>           <C>        <C>               <C>                  <C>
Collars                         2002         29,440        3.56          5.14            -            3.25 - 3.88          9,149
                                2003         25,550        3.34          4.97            -            3.72 - 4.24          1,937

Swaps -Short Natural Gas        2002          5,520          -            -             3.01          3.25 - 3.88         (2,321)
                                2003         14,600          -            -             3.19          3.72 - 4.24         (9,954)

Swaps - Long Natural Gas        2002          3,920          -            -         2.44 - 3.91       3.25 - 3.95            947
                                2003          2,110          -            -         3.10 - 4.00       3.72 - 4.04          1,017
----------------------------- ---------- ------------- ------------ ------------- ----------------- ----------------- --------------
                                             81,140                                                                         775
----------------------------- ---------- ------------- ------------ ------------- ----------------- ----------------- --------------
</TABLE>


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
         Type of Contract    Year of Maturity       Volumes                                                               Fair Value
                                                    Barrels           Fixed Price $           Current Price $               ($000)
--------------------------- -------------------- ----------------- --------------------- ------------------------- -----------------

                Oil
<S>                              <C>                     <C>         <C>                     <C>                            <C>
Swaps - Long Fuel Oil              2002                   163,474     19.75 - 24.49           24.58 - 24.93                   486
                                   2003                   346,892     20.10 - 26.72           22.19 - 23.94                   405
                                   2004                     3,894     23.50 - 23.70           23.23 - 23.32                     7
--------------------------- -------------------- ----------------- --------------------- ------------------------- -----------------
                                                          514,260                                                             898
--------------------------- -------------------- ----------------- --------------------- ------------------------- -----------------
</TABLE>


<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
      Type of Contract      Year of                                             Current Price   Estimated Profit $     Fair Value
                            Maturity         MWh         Fixed Profit /Price $        $                                  ($000)
------------------------ --------------- ------------ ------------------------- --------------- ------------------- ----------------

         Electricity
<S>                          <C>            <C>            <C>                    <C>             <C>                       <C>
Tolling Arrangements          2002           732,800         26.00 - 56.50            -            4.07 - 49.07                1,635

Swaps - Long                  2002            35,328         58.70 - 60.01          26.02               -                    (1,121)
                              2003            70,080         58.70 - 60.01          28.25               -                    (2,067)
------------------------ --------------- ------------ ------------------------- --------------- ------------------- ----------------
                                             838,208                                                                         (1,553)
------------------------ --------------- ------------ ------------------------- --------------- ------------------- ----------------
</TABLE>

Non-firm Gas Sales Derivative Instruments: Utility tariffs applicable to certain
large-volume  customers  permit  gas to be sold at  prices  established  monthly
within a specified range expressed as a percentage of prevailing  alternate fuel
oil prices. We used natural gas swap contracts, with offsetting positions in oil
swap contracts of equivalent energy value, to hedge the cash-flow variability of
specified  portions  of  gas  purchases  and  sales.  All  positions  that  were
outstanding  at December 31, 2001 settled  during the first  quarter of 2002. We
intend to enter into  additional  derivative  instruments  of this nature during
2002 if market conditions so warrant.

Firm Gas  Sales  Derivative  Instruments  -  Regulated  Utilities:  We have also
utilized  derivative  financial  instruments to reduce the cash flow variability
associated  with the  purchase  price for a portion  of our future  natural  gas
purchases.  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 support our gas
sales prices to regulated  firm gas sales  customers,  the  accounting for these
derivative  instruments is subject to SFAS 71. 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  during  the  appropriate  winter
heating season consistent with regulatory requirements.

The following tables set forth selected financial data associated with these
derivative financial instruments that were outstanding at June 30, 2002.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------

         Type of Contract   Year of Maturity       Volumes                                                                Fair Value
                                                    Mmcf              Fixed Price $            Current Price $              ($000)
-------------------------- -------------------- ----------------- ----------------------- ------------------------- ----------------

                Gas
<S>                              <C>                     <C>          <C>                      <C>                           <C>
Call Options                      2002                     1,280       4.20 - 4.50              3.69 - 3.95                    17
                                  2003                     1,960       4.20 - 4.50              3.88 - 4.04                   253
-------------------------- -------------------- ----------------- ----------------------- ------------------------- ----------------
                                                           3,240                                                              270
-------------------------- -------------------- ----------------- ----------------------- ------------------------- ----------------
</TABLE>

<PAGE>

Contract Review

On April 1, 2002 we implemented Implementation Issue C15 and C16 of Statement of
Financial Accounting  Standards No. 133, "Accounting for Derivative  Instruments
and Hedging  Activities" as amended and interpreted  incorporating  SFAS 137 and
138 and certain  implementation  issues  (collectively  "SFAS  133").  Issue C15
establishes  new criteria  that must be satisfied in order for  option-type  and
forward  contracts in electricity to be exempted as normal  purchases and sales,
while Issue C16  relates to  contracts  that  combine a forward  contract  and a
purchased  option  contract.  Based  upon a  review  of our  physical  commodity
contracts,  we determined  that certain  contracts for the physical  purchase of
natural gas can no longer be exempted as normal  purchases from the requirements
of SFAS 133.  As a result,  and  effective  April 1, 2002,  such  contracts  are
required to be recorded on the Consolidated  Balance Sheet at fair value and had
a calculated fair value at that date of $7.8 million.  At June 30, 2002 the fair
value of these  contracts  was $5.0 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  will be  recorded  as a  Regulatory  Asset or
Regulatory Liability on the Consolidated Balance Sheet.

Interest  Rate  Swaps:  We also  have  interest  rate swap  agreements  in which
approximately $1.3 billion of fixed rate debt has been synthetically modified to
floating rate debt.  For the term of the  agreements,  we will receive the fixed
coupon rate  associated  with these bonds and pay the counter parties a variable
interest  rate that is reset on a quarterly  basis.  These swaps are fair- value
hedges and qualify for "short-cut"  hedge  accounting  treatment under SFAS 133.
Through  the  utilization  of our  interest  rate swap  agreements,  we  reduced
recorded  interest  expense by $22.7  million for the six months  ended June 30,
2002.  The fair values of these  derivative  instruments  are  provided to us by
third party  appraisers  and represent  the present  value of future  cash-flows
based  on a  forward  interest  rate  curve  for  the  life  of  the  derivative
instrument.

During the quarter ended June 30, 2002, the swap  arrangement  associated with a
$90 million Gas Facilities  Revenue Bond was terminated by our counter party. At
that time we had an immaterial  derivative asset recorded. As provided for under
the terms of the swap  agreement,  our counter  party had the right to terminate
the swap arrangement at their discretion without a fee or penalty. Since neither
a fee nor penalty was imposed on the counter-party, the termination of this swap
arrangement had no earnings impact.

The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at June 30, 2002.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                                            Average Variable Rate
                              Maturity Date of       Notional Amount        Fixed Rate               Paid                Fair Value
                   Bond             Swaps                 ($000)             Received            Year to Date              ($000)
--------------------------- ---------------------- ----------------------- ---------------- ----------------------- ---------------
<S>                                         <C>                <C>           <C>                   <C>                      <C>
Medium Term Notes                            2010                 500,000     7.625%                4.290%                   3,022

Medium Term Notes                            2006                 500,000     6.150%                3.320%                   4,581

Medium Term Notes                            2023                 270,000     8.200%                3.620%                   (309)
--------------------------- ---------------------- ----------------------- ---------------- ----------------------- ---------------
                                                                1,270,000                                                    7,294
--------------------------- ---------------------- ----------------------- ---------------- ----------------------- ---------------
</TABLE>

<PAGE>

Additionally,  we also have an interest rate swap agreement that hedges the cash
flow  variability  associated  with  the  forecasted  issuance  of a  series  of
commercial paper offerings. The maximum length of time over which we have hedged
such cash flow  variability is through March 2003. The estimated amount of gains
or losses  associated  with such  derivative  instruments  that are  reported in
accumulated other comprehensive  income and that are expected to be reclassified
into  earnings  over the  next  twelve  months  is a loss of $1.6  million.  The
measured amount of hedge  ineffectiveness was immaterial.  We estimate that a 1%
increase in current  interest rates would result in a $10.3 million  increase to
interest expense.

Derivative  contracts are  primarily  used to manage our exposure to market risk
arising  from changes in commodity  prices and interest  rates.  In the event of
nonperformance by a counter party to derivative contract, the desired impact may
not be  achieved.  The  risk of a  counter  party  nonperformance  is  generally
considered  credit risk and is actively  managed by assessing each counter party
credit  profile and  negotiating  appropriate  levels of  collateral  and credit
support.  Currently the majority of our derivative contracts are with investment
grade companies.  (See Item 3.  Quantitative and Qualitative  Disclosures  About
Market Risk for a discussion on credit risk.)

7.   WORKFORCE REDUCTION PROGRAMS

As a result of the Eastern  acquisition,  we  implemented  early  retirement and
severance programs in an effort to reduce our workforce.  In 2000, we recorded a
$22.7 million liability  associated with these programs.  This severance program
is targeted to reduce the workforce by 500  employees and will continue  through
2002.  In 2001,  we reduced this  liability by $4.1 million as a result of lower
than  anticipated  costs per  employee.  As of June 30, 2002,  we had paid $12.3
million for these programs and had a remaining liability of $6.3 million.

8.  RECENT ACCOUNTING PRONOUNCEMENTS

On January 1, 2002, we adopted SFAS 141, "Business  Combinations",  and SFAS 142
"Goodwill  and  Other  Intangible  Assets".   The  key  concepts  from  the  two
interrelated  Statements  include  mandatory  use of the  purchase  method  when
accounting for business combinations, discontinuance of goodwill amortization, a
revised  framework for testing goodwill  impairment at a "reporting unit" level,
and new criteria for the  identification  and  potential  amortization  of other
intangible assets.  Other changes to existing  accounting  standards involve the
amount of goodwill to be used in determining the gain or loss on the disposal of
assets, and a requirement to test goodwill for impairment at least annually. The
annual impairment test is to be performed within six months of adopting SFAS 142
with any  resulting  impairment  reflected  as  either a  change  in  accounting
principle,  or a charge  to  operations  in the  financial  statements.  We have
completed our analysis for all of our  reporting  units and  determined  that no
consolidated impairment exists.

<PAGE>

For the  three  and six  months  ended  June  30,  2001  respectively,  goodwill
amortization was recorded in each segment as follows:  Gas Distribution $8.9 and
$17.8 million; Energy Services $2.1 and $4.2 million; and Energy Investments and
other $1.6 and $3.1 million.  As required by SFAS 142, below is a reconciliation
of  reported  net income for the three and six  months  ended June 30,  2001 and
pro-forma net income,  for the same period,  adjusted for the  discontinuance of
goodwill amortization.
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                                              Three Months Ended   Three Months Ended     Six Months Ended      Six Months Ended
                                                June 30, 2002         June 30, 2001        June 30, 2002         June 30, 2001
-------------------------------------------- --------------------- -------------------- --------------------- ---------------------
<S>                                                        <C>                <C>                   <C>                   <C>
Earnings (loss) available for common stock             $    8,036          $   (8,001)            $  221,191            $  215,298
   Add back: goodwill amortization                              -               12,594                     -                25,145
-------------------------------------------- --------------------- -------------------- --------------------- ---------------------
Adjusted net income                                         8,036                4,593               221,191               240,443
-------------------------------------------- --------------------- -------------------- --------------------- ---------------------

Basic earnings (loss) per share                              0.06               (0.06)                  1.57                  1.57
   Add back: goodwill amortization                              -                 0.09                     -                  0.18
-------------------------------------------- --------------------- -------------------- --------------------- ---------------------
Adjusted basic earnings per share                       $    0.06            $    0.03             $    1.57             $    1.75
-------------------------------------------- --------------------- -------------------- --------------------- ---------------------

Diluted earnings (loss) per share                            0.06               (0.06)                  1.56                  1.55
Add back: goodwill amortization                                 -                 0.09                     -                  0.18
-------------------------------------------- --------------------- -------------------- --------------------- ---------------------
Adjusted diluted earnings per share                     $    0.06            $    0.03             $    1.56             $    1.73
-------------------------------------------- --------------------- -------------------- --------------------- ---------------------
</TABLE>

In July of 2001, the FASB issued SFAS No. 143,  "Accounting for Asset Retirement
Obligations".  The  Standard  requires  entities  to record  the fair value of a
liability  for an  asset  retirement  obligation  in the  period  in which it is
incurred. When the liability is initially recorded, the entity will capitalize a
cost by increasing the carrying  amount of the related  long-lived  asset.  Over
time, the liability is accreted to its then present value,  and the  capitalized
cost is depreciated  over the useful life of the related asset.  Upon settlement
of the  liability,  an entity  either  settles the  obligation  for its recorded
amount or incurs a gain or loss upon  settlement.  The standard is effective for
fiscal years beginning after June 15, 2002, with earlier application encouraged.
We are currently  evaluating the impact, if any, that this Statement may have on
our results of operations and financial position.

SFAS No. 144,  "Accounting for the Impairment or Disposal of Long-Lived Assets",
was effective  January 1, 2002,  and addresses  accounting and reporting for the
impairment or disposal of long-lived  assets.  SFAS No. 144 supersedes  SFAS No.
121,  "Accounting  for the  Impairment of Long-Lived  Assets and for  Long-Lived
Assets to Be  Disposed  Of" and APB Opinion  No. 30,  "Reporting  the Results of
Operations-Reporting  the Effects of Disposal of a Segment of a Business".  SFAS
No. 144  retains  the  fundamental  provisions  of SFAS No. 121 and  expands the
reporting of discontinued operations to include all components of an entity with
operations that can be  distinguished  from the rest of the entity and that will
be  eliminated  from  the  ongoing  operations  of  the  entity  in  a  disposal
transaction.  As of June 30, 2002, implementation of this Statement did not have
a significant effect on our results of operations and financial position.

<PAGE>

9. DISCONTINUED OPERATIONS

On November 8, 2000, we acquired Midland  Enterprises LLC ("Midland"),  a marine
transportation  subsidiary,  as part of the  Eastern  acquisition.  In its order
issued under PUCHA approving the  acquisition,  the SEC required us to sell this
subsidiary  by November 8, 2003  because its  operations  were not  functionally
related to our core utility operations. On July 2, 2002 we completed the sale of
Midland to Ingram Industries Inc.

Discontinued  operations  for the year  ended  December  31,  2001  included  an
anticipated after-tax loss on disposal of $30.4 million. As a result of a change
in our tax  structuring  strategy  related  to the sale of  Midland,  during the
quarter ended June 30, 2002,  we recorded an  additional  provision for city and
state taxes and made  adjustments  to the  estimations  used in the December 31,
2001 loss provision.  These changes  resulted in an additional after tax loss on
disposal of $19.7 million.

The following is selected financial information for Midland for the three and
six months ended June 30, 2002 and June 30, 2001:
<TABLE>
<CAPTION>

                                                                                                          (In Thousands of Dollars)
------------------------------------------------------------------------------------------------------------------------------------
                                                    Three Months          Three Months         Six Months           Six Months
                                                      Ended                  Ended                Ended                Ended
                                                  June 30, 2002          June 30, 2001        June 30, 2002        June 30, 2001
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>                   <C>                  <C>                  <C>
Revenues                                     $              60,260   $            67,776  $            116,149  $           135,364
Pretax income (loss)                                         (888)                 6,368               (4,624)                7,857
Income tax (expense) benefit                                   235               (2,476)                 1,268              (3,304)
------------------------------------------------------------------------------------------------------------------------------------
Income (loss) from discontinued operations                   (653)                 3,892               (3,356)                4,553
------------------------------------------------------------------------------------------------------------------------------------
Loss on disposal                                          (19,009)                     -              (16,306)                    -
------------------------------------------------------------------------------------------------------------------------------------
Loss from discontinued operations            $            (19,662)  $              3,892  $           (19,662)  $             4,553
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


Assets and liabilities of the discontinued operations are as follows:
<TABLE>
<CAPTION>

                                                                                                (In Thousands of Dollars)
                    --------------------------------------------------------------------------------------------------------------
                                                                               June 30, 2002                December 31, 2001
                    --------------------------------------------------------------------------------------------------------------
                    <S>                                                               <C>                              <C>
                    Current assets                                      $                136,193   $                      139,522
                    Property, plant and equipment, net                                   308,707                          316,626
                    Long-term assets                                                      33,703                           35,233
                    Current liabilities                                                 (49,750)                         (58,835)
                    Long-term liabilities                                              (238,718)                        (241,491)
                    --------------------------------------------------------------------------------------------------------------
                    Net assets held for disposal                        $                190,135   $                      191,055
                    --------------------------------------------------------------------------------------------------------------
</TABLE>

10.         LEGAL MATTERS

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.

<PAGE>

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 of the Roy Kay companies through the
July 17th announcement.

Furthermore, 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 by KeySpan Services,  Inc., a KeySpan subsidiary.  Finally, 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.  We are unable to
determine the outcome of these proceedings and what effect, if any, such outcome
will have on our financial condition, results of operations or cash flows.

On June 14, 2002,  a complaint  was filed by Donna Gay, et al.  against  KeySpan
Corporation   in  the  United  States   District   Court  for  the  District  of
Massachusetts.   The  complaint  alleges   liabilities   stemming  from  alleged
environmental contaminants at the Oxbow Site in Everett,  Massachusetts. On June
26,  2002,  a complaint  was filed by Beazer  East,  Inc.  in the United  States
District Court for the Eastern District of New York,  seeking both  contribution
from KeySpan for costs and  declaratory  relief as to the respective  former and
future  liabilities  associated  with  responding  to the  actual or  threatened
release of hazardous substances into the environment and the Everett site.

In June 2002, Hawkeye Electric,  LLC et al.  ("Hawkeye")  commenced an action in
New York State Supreme Court,  Suffolk County against KeySpan and certain of its
subsidiaries  alleging,  among other things,  that KeySpan and its  subsidiaries
breached  certain  contractual  obligations  to  Hawkeye  with  respect  to  the
provision of certain gas, electric and telecommunications  construction services
offered by  Hawkeye.  Hawkeye is seeking  damages in excess of $90  million  and
KeySpan has alleged a number of  counterclaims  seeking  damages in excess of $4
million. At this time, we are unable to determine the outcome of this proceeding
and what  effect,  if any,  such outcome  will have on our  financial  position,
results of operation or cash flow.

<PAGE>

11. KEYSPAN GAS EAST CORPORATION SUMMARY FINANCIAL INFORMATION

KEDLI, a wholly owned subsidiary of KeySpan, established a program for the
issuance, from time to time, of up to $600 million aggregate principal amount of
medium term notes, which are unconditionally guaranteed by us. 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 15, 2008. The following condensed financial statements are required to
be disclosed by SEC regulations and are those of KEDLI and KeySpan as guarantor
of the medium term notes.

<TABLE>
<CAPTION>
Statement of Income
                                                                                                         (In  Thousands of Dollars)
------------------------------------------------------------------------------------------------------------------------------------
                                    Three Months Ended June 30, 2002                              Three Months Ended June 30, 2001
------------------------------------------------------------------------------------------------------------------------------------

                          Guarantor       KEDLI    Eliminations   Consolidated    Guarantor       KEDLI   Eliminations  Consolidated
<S>                      <C>            <C>            <C>        <C>           <C>            <C>           <C>       <C>
Revenues                  $1,078,169  $  137,936                 $  1,216,105   $ 1,182,782   $ 156,520                $1,339,302
Operating Expenses
Purchased Gas                187,369      62,573                      249,942       273,680      74,669                   348,349
Fuel and purchased power      93,292           -                       93,292       146,357           -                   146,357
Operations and maintenance   535,027      13,067                      548,094       517,176      16,627                   533,803
Intercompany expense         (20,034)     20,034                            -       (21,216)     21,216                         -
Depreciation and
 amortization                112,124      15,339                      127,463       108,156      13,422                   121,578
Operating Taxes               68,080      19,308                       87,388        81,214      19,621                   100,835
                          ----------- ------------ ------------- --------------  ------------- ---------- ------------ -------------
Total Operating
  Expenses                   975,858     130,321                    1,106,179     1,105,367     145,555                 1,250,922
                          ----------- ------------ ------------- --------------  ------------- ---------- ------------ -------------
Operating Income             102,311       7,615                       109,926       77,415      10,965                    88,380
Other Income and
  (Deductions)                 6,023       2,192         (5,869)         2,346       (1,137)      3,588       (5,607)      (3,156)
                          ----------- ------------ ------------- --------------  ------------- ---------- ------------ -------------
Income Before Interest
Charges and Income Taxes      108,334       9,807        (5,869)       112,272       76,278      14,553       (5,607)      85,224

Interest Expense               60,023      15,900        (5,869)        70,054       81,896      15,638       (5,607)      91,927
Income Taxes                   15,768      (2,724)                      13,044        4,520        (806)                    3,714
Preferred stock dividends       1,476           -              -         1,476        1,476           -             -       1,476
                          ----------- ------------ ------------- --------------  ------------- ---------- ------------ -------------
Earnings (Loss) From
 Continuing Operations    $    31,067 $    (3,369)  $          - $      27,698 $    (11,614) $     (279) $          -  $  (11,893)
                          =========== ============ ============= ==============  ============= ========== ============ =============
</TABLE>

<TABLE>
<CAPTION>

Statement of Income
                                                                                                        (In Thousands of Dollars)
------------------------------------------------------------------------------------------------------------------------------------
                                     Six Months Ended June 30, 2002                                  Six Months Ended June 30, 2001
------------------------------------------------------------------------------------------------------------------------------------
                           Guarantor     KEDLI      Eliminations    Consolidated   Guarantor      KEDLI   Eliminations  Consolidated
<S>                        <C>           <C>              <C>         <C>          <C>            <C>         <C>        <C>
Revenues                  $ 2,630,780   $ 456,884                   $   3,087,664  $ 3,327,372   $ 587,018               $ 3,914,390
Operating Expenses
Purchased Gas                 693,859     205,440                         899,299    1,212,899     332,799                 1,545,698
Fuel and purchased power      177,664           -                         177,664      289,657           -                   289,657
Operations and maintenance  1,016,593      25,067                       1,041,660    1,005,915      31,771                 1,037,686
Intercompany expense          (38,242)     38,242                               -      (42,760)     42,760                         -
Depreciation and
  amortization                217,879      35,581                         253,460      220,290      32,452                   252,742
Operating Taxes               163,087      44,694                         207,781      193,218      49,607                   242,825
                          ------------- ------------ --------------- ------------- ------------- ----------- ----------- -----------
Total Operating
  Expenses                   2,230,840     394,024                       2,579,864    2,879,219     489,389                3,368,608
                          ------------- ------------ --------------- ------------- ------------- ----------- ----------- -----------
Operating Income              399,940     107,860                         507,800      448,153      97,629                   545,782
Other Income and
  (Deductions)                 16,478       5,095           (11,040)       10,533        8,142       6,579     (13,175)        1,546
                          ------------- ------------ --------------- ------------- ------------- ----------- ----------- -----------
Income Before Interest
  Charges and Income Taxes    416,418     112,955           (11,040)      518,333      456,295     104,208     (13,175)      547,328
Interest Expense              122,599      31,102           (11,040)      142,661      165,527      32,878     (13,175)      185,230
Income Taxes                   97,507      34,360                         131,867      124,156      24,245                   148,401
Preferred stock dividends       2,952           -                 -         2,952        2,952           -           -         2,952
                          ------------- ------------ --------------- ------------- ------------- ----------- ----------- -----------
Earnings (Loss) from
  Continuing Operations    $  193,360  $   47,493    $            -  $    240,853  $   163,660   $  47,085   $       -   $   210,745
                          ============= ============ =============== ============= ============= =========== =========== ===========
</TABLE>

<PAGE>

<TABLE>
<CAPTION>
Balance Sheet                                                                                        (In Thousands of Dollars)
---------------------------------------- -------------------------------------------------------------------------------------------
                                              June 30, 2002                                               December 31, 2001
---------------------------------------- ----------------------------------------------------- -------------------------------------

ASSETS                      Guarantor      KEDLI    Eliminations   Consolidated   Guarantor     KEDLI     Eliminations  Consolidated
<S>                         <C>          <C>         <C>          <C>          <C>           <C>           <C>            <C>
Current Assets
  Cash and temporary
    cash investments         $ 137,599    $     -   $        -    $  137,599    $  159,252   $       -     $      -      $   159,252
  Accounts Receivable, net   1,226,822    166,472     (245,710)    1,147,584     1,540,082     233,013     (500,496)       1,272,599
  Other current assets         441,735    124,640            -       566,375       454,319     112,317            -          566,636
                            ------------ -------------------------------------------------------------------------------------------
                             1,806,156    291,112     (245,710)    1,851,558     2,153,653     345,330     (500,496)       1,998,487
                            ------------ -------------------------------------------------------------------------------------------
Assets Held for Disposal       190,135          -            -       190,135       191,055           -            -          191,055
Equity Investments             774,204          -     (532,862)      241,342       756,111           -     (532,862)        223,249
                            ------------ -------------------------------------------------------------------------------------------
Property
  Gas                        4,187,083   1,690,538           -     5,877,621     4,074,894   1,629,963            -       5,704,857
  Other                      4,607,133           -           -     4,607,133     4,231,262           -            -       4,231,262
  Accumulated depreciation
    and depletion           (3,219,722)   (310,590)          -    (3,530,312)   (3,035,788)   (294,400)           -      (3,330,188)
                            ------------ -------------------------------------------------------------------------------------------
                             5,574,494   1,379,948           -     6,954,442     5,270,368   1,335,563            -       6,605,931
                            ------------ -------------------------------------------------------------------------------------------

Deferred Charges             2,528,605     183,448           -     2,712,053     2,571,029     199,855            -       2,770,884
                            --------------------------------------------------------------------------------------------------------

Total Assets                $10,873,594 $1,854,508  $ (778,572)  $11,949,530   $10,942,216  $1,880,748  $(1,033,358)   $ 11,789,606
                            ========================================================================================================

LIABILITIES
AND CAPITALIZATION

Current Liabilities
  Accounts Payable
    and accrued expenses   $   928,221   $   77,852 $        -   $ 1,006,073     $ 975,873 $   115,557   $        -     $ 1,091,430
  Commercial Paper             570,655            -          -       570,655     1,048,450           -            -       1,048,450
  Other current
    liabilities                118,469       79,923          -       198,392       220,985      23,844            -         244,829
                            --------------------------------------------------------------------------------------------------------
                             1,617,345      157,775          -     1,775,120     2,245,308     139,401            -       2,384,709
                            --------------------------------------------------------------------------------------------------------
Intercompany
   Accounts Payable                  -       69,806    (69,806)            -             -    324,592      (324,592)              -
                            --------------------------------------------------------------------------------------------------------
Deferred Credits
   and Other Liabilities

  Deferred Income Tax          636,863      174,486          -       811,349       593,300       4,772            -         598,072
  Other deferred credits
   and liabilities             833,550       93,417          -       926,967       841,662      100,452           -         942,114
                            --------------------------------------------------- ----------------------------------------------------
                             1,470,413      267,903          -     1,738,316     1,434,962      105,224           -       1,540,186
                            --------------------------------------------------- ----------------------------------------------------

Capitalization
  Common shareholders'
    equity                   2,831,009      658,120   (532,862)    2,956,267     2,812,837      610,627    (532,862)      2,890,602
  Preferred stock               84,077            -          -        84,077        84,077            -           -          84,077
  Long-term debt             4,667,217      700,904   (175,904)    5,192,217     4,172,649      700,904    (175,904)      4,697,649
                            --------------------------------------------------------------------------------------------------------
Total Capitalization         7,582,303    1,359,024   (708,766)    8,232,561     7,069,563    1,311,531    (708,766)      7,672,328
                            --------------------------------------------------------------------------------------------------------
Minority Interest
  in Subsidiary Companies      203,533            -          -       203,533       192,383            -           -         192,383
                            --------------------------------------------------------------------------------------------------------
Total Liabilities
  and Capitalization       $10,873,594  $  1,854,508 $(778,572)  $11,949,530   $10,942,216 $  1,880,748  $(1,033,358)  $ 11,789,606
                            ========================================================================================================
</TABLE>

<PAGE>

<TABLE>
<CAPTION>

 Statement of Cash Flows                                                                                 (In Thousands of Dollars)
------------------------------------------------------------------------------------------------------------------------------------
                                             Six Months Ended June 30, 2002                   Six Months Ended June 30, 2001
------------------------------------------------------------------------------------ -----------------------------------------------
                                   Guarantor           KEDLI         Consolidated      Guarantor         KEDLI          Consolidated
------------------------------------------------ -------------- ------------------ --------------- ---------------- ----------------
Operating Activities
<S>                                <C>              <C>              <C>              <C>             <C>              <C>
Net Cash Provided by
   Operating Activities        $     395,573      $   288,184    $       683,757    $   473,124     $   81,746       $    554,870
                               ----------------- -------------- ------------------ --------------- ---------------- ----------------
Investing Activities

Capital expenditures                (534,831)         (60,672)         (595,503)       (396,786)       (28,021)           (424,807)
Sale of Assets                             -                -                 -          18,458              -              18,458
Other                                      -                -                 -          (7,822)             -              (7,822)
                               ----------------- -------------- ------------------ --------------- ---------------- ----------------
Net Cash Used in
   Investing Activities             (534,831)         (60,672)         (595,503)       (386,150)       (28,021)           (414,171)
                               ----------------- -------------- ------------------ --------------- ---------------- ----------------
Financing Activities

Issuance of Treasury Stock            51,896                -            51,896           64,107              -             64,107
Issuance of long-term debt           507,754                -           507,754          583,000        125,000            708,000
Payment of long-term debt            (54,590)               -           (54,590)        (152,000)             -           (152,000)
Payment of commercial paper         (477,795)               -          (477,795)        (497,033)             -           (497,033)
Preferred stock dividends paid        (2,952)               -            (2,952)          (2,952)             -             (2,952)
Common stock dividends paid         (124,684)               -          (124,684)        (121,937)             -           (121,937)
Net intercompany accounts
  payable                             227,512         (227,512)                -          178,725       (178,725)                -
Other                                 (9,536)               -            (9,536)           5,102              -              5,102
                               ----------------- -------------- ------------------ --------------- ---------------- ----------------
Net Cash Provided by
   (Used in) Financing
  Activities                    $    117,605      $  (227,512)     $   (109,907)    $     57,012    $    (53,725)    $       3,287
                               ----------------- -------------- ------------------ --------------- ---------------- ----------------
Net Increase in Cash and
   Cash Equivalents             $    (21,653)     $         -      $    (21,653)    $    143,986    $         -      $     143,986
                               ================= ============== ================== =============== ================ ================
Cash and Cash Equivalents at
   Beginning of Period          $    159,252      $         -      $    159,252     $     83,329              -      $      83,329
                               ----------------- -------------- ------------------ --------------- ---------------- ----------------

Cash and Cash Equivalents at
   End of Period                $    137,599       $        -      $    137,599     $    227,315    $         -      $     227,315
                               =================== ============== ================ =============== ================ ================
</TABLE>












<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 and six
months ended June 30, 2002,  compared to the three and six months ended June 30,
2001.  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.

Consolidated  earnings from  continuing  operations for the three and six months
ended June 30, 2002 were $27.7 million,  or $0.20 per share and $240.9  million,
or  $1.71  per  share,   respectively.   Consolidated  results  from  continuing
operations  for the three months  ended June 30, 2001  reflected a loss of $11.9
million, or $0.09 per share.  Consolidated  earnings from continuing  operations
for the six months ended June 30, 2001 were $210.7 million,  or $1.54 per share.
Earnings available for common stock, which includes  discontinued  operations as
discussed below,  were $8.0 million,  or $0.06 per share and $221.2 million,  or
$1.57 per share for the three and six months ended June 30, 2002,  respectively.
Earnings  available  for common  stock for the three  months ended June 30, 2001
reflected a loss of $8.0 million,  or $0.06 per share.  For the six months ended
June 30, 2001 earnings available for common stock were $215.3 million,  or $1.57
per share.  Diluted  earnings  per share were $1.56 and $1.55 for the six months
ended June 30, 2002 and 2001, respectively. Basic and diluted earnings per share
were the same for the three months ended June 30, 2002 and 2001, respectively.

Average  common  shares  outstanding  for the six  months  ended  June 30,  2002
increased  by  2.3%  compared  to the  same  period  last  year  reflecting  the
re-issuance  of shares held in treasury  pursuant to dividend  reinvestment  and
employee  benefit  plans.  This increase in average  common  shares  outstanding
reduced  earnings  per share for the six  months  ended  June 30,  2002 by $0.04
compared to the corresponding period in 2001.

On January 24, 2002, we announced  that we had entered into an agreement to sell
Midland Enterprises LLC ("Midland"),  our marine barge business. In anticipation
of this  divestiture,  which closed on July 2, 2002, we have reported  Midland's
operations as discontinued for 2002 and 2001. (See our Annual Report on Form 10K
for the year  ended  December  31,  2001  Item 7  "Management's  Discussion  and
Analysis of Financial Conditions and Results of Operations",  as well as Note 10
to those Consolidated  Financial Statements  "Discontinued  Operations".) In the
fourth  quarter of 2001, we recorded an estimated loss on the sale of Midland as
well as an estimate for Midland's results of operations for the first six months
of 2002.  During the three months ended June 30, 2002, we recorded an additional
after-tax  loss of $19.7 million,  primarily  reflecting a provision for certain

<PAGE>

city  and  state  taxes  that  resulted  from a  change  in our tax  structuring
strategy.  (See Note 9 to the Consolidated  Financial  Statements  "Discontinued
Operations" for further disclosures on the sale of Midland.)

As discussed in more detail below,  results from  continuing  operations for the
quarter and six months  ended June 30, 2002 verses the  comparable  periods last
year were  principally  impacted  by the  following  four  factors:  (i)  losses
incurred   in  2001  by  one  of  our   unregulated   subsidiaries;   (ii)   the
discontinuation of goodwill  amortization in 2002; (iii) a significant  decrease
in  interest  expense;  and (iv) a  significant  decrease in natural gas prices,
which reduced  comparative  earnings  associated  with the operations of our gas
exploration and production activities.

In 2001,  we  discontinued  the general  contracting  activities  related to the
former Roy Kay companies, with the exception of work to be completed on existing
contracts,  based upon our view that the general contracting  business was not a
core  competency  of these  companies.  Losses  incurred  by the  former Roy Kay
companies  for the three and six months  ended June 30, 2001 were $30.1  million
after-tax,  or $0.22 per share and $35.6 million after-tax,  or $0.26 per share,
respectively. (See our Annual Report on Form 10K for the year ended December 31,
2001 Item 7  "Management's  Discussion  and Analysis of Financial  Condition and
Results of Operations" and Note 10 to those  Consolidated  Financial  Statements
"Roy Kay Operations"  for a more detailed  discussion.) We are in the process of
completing  the contracts  entered into by the former Roy Kay companies and, for
the three and six months ended June 30, 2002,  we incurred  after-tax  losses of
$1.5  million  and  $2.8  million,   respectively,   reflecting  overhead,   and
administrative and general expenses. These costs could not be accrued in 2001.

In January  2002,  we adopted  Statement  of  Accounting  Standard  ("SFAS") 142
"Goodwill and Other Intangible  Assets".  The key requirements of this Statement
include the  discontinuance  of goodwill  amortization,  a revised framework for
testing  goodwill   impairment  and  new  criteria  for  the  identification  of
intangible  assets.  Consolidated  goodwill  amortization  for the three and six
months  ended June 30,  2001 was $12.6  million,  or $0.09 per share,  and $25.2
million, or $0.18 per share, respectively.

Interest  expense  decreased by $21.9 million  ($14.2  after-tax),  or $0.10 per
share and $42.6 million  ($27.7 million  after-tax) or $0.20 per share,  for the
three and six months ended June 30,  2002,  respectively.  The weighted  average
interest rate on outstanding  commercial  paper during the six months ended June
30,  2002 was  approximately  2.08%  compared  to  approximately  5.51%  for the
corresponding  period last year, a decrease of  approximately  340 basis points.
Further,  we have a number of  interest  rate swap  agreements  in which we have
effectively  changed  fixed rate debt to  floating  rate debt.  Our use of these
derivative  instruments has reduced interest expense by $22.7 million during the
six  months  ended  June 30,  2002.  (See Note 6 to the  Consolidated  Financial
Statements  "Derivative  Financial  Instruments"  for  a  description  of  these
instruments.)

<PAGE>

For the three and six  months  ended  June 30,  2002,  net  income  from our gas
exploration and production  operations  decreased by $12.0 million, or $0.09 per
share and by $38.8  million,  or $0.29 per share,  respectively  compared to the
corresponding periods last year. Our gas exploration and production subsidiaries
were adversely  impacted by  significantly  lower realized gas prices during the
six months ended June 30, 2002 compared to the same period in 2001.

Income  tax  expense  generally  reflects  the level of  pre-tax  income for all
periods reported.  Income tax expense also reflects tax benefits of $6.4 million
and $11.9  million  recognized  in the three and six months ended June 30, 2002,
respectively, resulting from the favorable resolution of certain outstanding tax
issues related to the KeySpan / Long Island Lighting  Company  ("LILCO")  merger
completed in May 1998. 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 merger.
This adjustment was the result of a revised  valuation study and the preparation
of an amended  tax return.  Concurrent  with the  deferred  tax  adjustment,  we
reduced current income taxes payable by $183.2 million,  resulting in a net $5.5
million income tax benefit.

Earnings before interest and taxes ("EBIT") increased by $27.1 million,  or 32%,
for the second quarter of 2002 compared to the corresponding  quarter last year,
but  decreased  by $29.0  million,  or 5% for the six months ended June 30, 2002
compared to the same period last year. Comparative EBIT results were impacted by
the items  mentioned  above,  namely (i) EBIT losses of $53.3  million and $61.2
million  incurred by the Roy Kay  companies  for the three and six months  ended
June 30, 2001,  respectively;  (ii) the discontinuation of goodwill amortization
in 2002 of $12.6  million and $25.2  million for the three and six months  ended
June 30, 2001,  respectively;  and (iii)  decreases in comparative  EBIT results
associated with our gas exploration and production subsidiaries of $20.4 million
and  $70.2   million  for  the  three  and  six  months  ended  June  30,  2002,
respectively.  The remaining decrease in EBIT from core operations for the three
and six months  ended June 30, 2002  compared to last year,  primarily  reflects
lower EBIT from our unregulated  affiliates.  See "Review of Operating Segments"
and Note 2 to the Consolidated  Financial  Statements  "Business Segments" for a
detailed discussion of EBIT results for each of our lines of business.

We are  maintaining  our earnings  guidance that was issued in December 2001. We
forecast that KeySpan's 2002 earnings from continuing  core operations  (defined
for this purpose as all continuing  operations  other than gas  exploration  and
production)  will be in the range of $2.40 to $2.45  per  share.  Earnings  from
continuing  core  operations  were  $0.11  per share and $1.56 per share for the
three and six months ended June 30, 2002, respectively.  KeySpan's 2002 earnings
forecast for its gas  exploration  and production  operations is in the range of
$0.20 - $0.30  per  share.  Earnings  from our gas  exploration  and  production
operations were $0.09 per share and $0.15 per share for the three and six months
ended June 30, 2002, respectively.  The earnings forecast may vary significantly
during  the  year  due to,  among  other  things,  changing  market  conditions,
especially  fluctuations  in natural gas and  electricity  prices,  which remain
volatile.

<PAGE>

Consolidated earnings are seasonal in nature due to the significant contribution
to earnings of our gas distribution operations. As a result, we expect to earn
approximately 60%, and 30% to 35% of our yearly earnings in the first and fourth
quarters of our fiscal year, respectively 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

The following discussion of financial results achieved by our operating segments
is  presented  on an EBIT  basis.  We use EBIT  measures  in our  financial  and
business  planning process to provide a reasonable  assurance that our financial
forecasts will provide,  among other things, (i) shareholders with a competitive
return on their  investment,  (ii) adequate  earnings to service debt; and (iii)
adequate   interest   coverage  to  maintain  or  improve  our  credit  ratings.
Information  concerning  EBIT is  presented  as a  measure  of  those  financial
results.  EBIT should not be construed as an alternative to operating  income or
cash  flow  from  operating  activities  as  determined  by  Generally  Accepted
Accounting Principles.


















<PAGE>




Gas Distribution

KeySpan Energy Delivery New York ("KEDNY") provides gas distribution  service to
customers in the New York City Boroughs of Brooklyn,  Queens and Staten  Island,
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.  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.
<TABLE>
<CAPTION>
                                                                                                         (In Thousands of Dollars)
-------------------------------------------- --------------------- --------------------- ----------------------- -------------------

                                               Three Months Ended      Three Months Ended     Six Months Ended    Six Months Ended
                                                  June 30, 2002           June 30, 2001         June 30, 2002       June 30, 2001
-------------------------------------------- --------------------- --------------------- --------------------- ---------------------
<S>                                                     <C>                    <C>                <C>                    <C>
Revenues                                                $ 521,822             $ 620,685           $ 1,744,791           $ 2,374,329
Cost of gas                                               236,357               328,487               849,939             1,433,795
Revenue taxes                                              18,163                21,163                56,458                77,642
-------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Net Revenues                                              267,302               271,035               838,394               862,892
-------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Operating expenses
  Operations and maintenance                              152,767               158,356               298,305               317,228
  Depreciation and amortization                            58,118                62,753               121,138               131,336
  Operating taxes                                          29,647                36,162                67,648                74,138
-------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Total Operating Expenses                                  240,532               257,271               487,091               522,702
-------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Operating Income                                           26,770                13,764               351,303               340,190
Other Income and (Deductions)                               2,473                 5,160                 7,596                 9,415
-------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Earnings Before Interest and Taxes                       $ 29,243              $ 18,924             $ 358,899               349,605
-------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Firm gas sales (MDTH)                                      41,391                36,516               148,665               163,332
Firm transportation (MDTH)                                 13,497                22,248                43,495                56,488
Transportation - Electric
      Generation   (MDTH)                                  13,182                11,754                26,541                16,132
Other sales (MDTH)                                         23,513                23,319                61,414                48,834
Warmer than normal -  New York                                  -                  7.4%                 15.0%                  2.0%
Warmer (Colder) than normal - New  England                  13.6%                (3.3%)                 10.1%                (2.3%)
-------------------------------------------- --------------------- --------------------- --------------------- ---------------------
</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.

<PAGE>

Net Revenues

Net gas revenues  (revenues less the cost of gas and  associated  revenue taxes)
associated  with  both our New  York  and New  England  based  gas  distribution
operations  were  adversely  impacted  by the  significantly  warmer than normal
weather  experienced  throughout the Northeastern  United States during the past
winter heating season.  Based on heating degree days,  weather for the first six
months of 2002 was the  warmest in the past 30 years (  approximately  10% - 15%
warmer than normal), and approximately 14% warmer than last year in our New York
and New  England  service  territories.  The  significantly  warmer  than normal
weather resulted in a decrease of $24.5 million,  or 3%, in net gas revenues for
the six months ended June 30, 2002,  compared to the  corresponding  period last
year.

KEDNY and KEDLI each  operate  under a utility  tariff  that  contains a weather
normalization  adjustment that largely  offsets  variations in firm net revenues
due to fluctuations in weather. These weather normalization adjustments resulted
in a $33.4  million  benefit to net gas revenues  during the first six months of
2002.   Nevertheless,   net  revenues  from  firm  gas  customers  (residential,
commercial and industrial customers) in our New York service territory decreased
by $17.9  million for the six months  ended June 30,  2002  compared to the same
period last year, primarily as a result of lower customer consumption due to the
extremely  warm weather,  offset,  in part, by the benefits from  conversions to
natural gas.

Net  revenues  from firm gas  customers  in our New  England  service  territory
decreased  by $4.6  million  for the first  half of 2002,  compared  to the same
period last year, also due to the extremely warm weather.  Our New England based
gas distribution  subsidiaries do not have a weather  normalization  adjustment.
Included  in net  revenues  for  the  six  months  ended  June  30,  2002 is the
beneficial  effect of a favorable ruling of the  Massachusetts  Supreme Judicial
Court  relating  to the  appeal by  Boston  Gas  Company  of a  decision  of the
Massachusetts  Department of Telecommunications and Energy ("DTE") on Boston Gas
Company's  Performance  Based  Rate  Plan  ("PBR").  The  court  found  that the
"accumulated  inefficiencies"  component of the productivity  factor in the PBR,
imposed by the Massachusetts  Department of  Telecommunications  and Energy, was
not supportable. This ruling resulted in a benefit to comparative net margins of
$5.3 million. (See our Annual Report on Form 10K for the year ended December 31,
2001,  Item 7 "Management's  Discussion and Analysis of Financial  Condition and
Results of Operations - Regulation and Rate Matters".)

Firm gas  distribution  rates in the first  quarter of 2002,  other than for the
recovery of gas costs, have remained substantially  unchanged from rates charged
last  year  in all  of our  service  territories.  To  mitigate  the  effect  of
fluctuations  in normal  weather  patterns on our  financial  position  and cash
flows,  we are currently  evaluating the  appropriateness  of employing  weather
derivatives for the 2002/2003 winter heating season.

In our large-volume heating markets and other interruptible  (non-firm) markets,
which include large  apartment  houses,  government  buildings and schools,  gas
service is provided  under rates that are  established to compete with prices of
alternative  fuel,  including  No. 2 and No. 6 grade heating oil. As a result of
the extremely  warm weather,  net margins  decreased $2.0 million during the six
months ended June 30, 2002,  compared to same period last year.  The majority of
interruptible  profits earned are returned to firm customers as an offset to gas
costs.

<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.

Sales, Transportation and Other Quantities

Firm gas sales and  transportation  quantities  decreased  by 13% during the six
months  ended  June 30,  2002,  compared  to the same  period in 2001 due to the
extremely  warm  weather in all our service  territories.  Net  revenues are not
affected by customers  choosing to purchase their gas supply from other sources,
since delivery rates charged to transportation  customers generally are the same
as the delivery component of 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.  We have an agreement  with Coral  Resources,  L.P.
("Coral"),  a subsidiary of Shell Oil Company,  under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI. We also have a portfolio  management contract with
El Paso Energy Marketing,  Inc. ("El Paso"), under which El Paso provides all of
the city gate supply  requirements at market prices and manages certain upstream
capacity, underground storage and term supply contracts for KEDNE. Our agreement
with El Paso expires on October 31, 2002 and our agreement with Coral expires on
March 31, 2003. We are currently  considering extending the El Paso agreement to
March 31, 2003.

Purchased Gas for Resale

The  decrease  in gas costs for the six  months  ended  June 30,  2002 of $583.9
million  reflects a decrease of 35% in the price per decatherm of gas purchased,
and an 11%  reduction  in the  quantity  of gas  purchased,  as a result  of the
extremely  warm  winter.  Fluctuations  in  utility  gas costs 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 cost  recoveries  are
deferred and refunded to or collected from customers in a subsequent period.

<PAGE>

Operating Expenses


Operating expenses decreased by $16.7 million,  or 7%, and by $35.6 million,  or
7%, for three and six months ended June 30, 2002, respectively,  compared to the
corresponding  periods last year.  The decrease in operating  expenses is due to
the discontinuance of goodwill amortization,  lower operating taxes, cost saving
synergies,  the effects of warmer than normal  weather and the timing of certain
operations and maintenance expenses.

In January  2002,  we adopted  Statement  of  Accounting  Standard  ("SFAS") 142
"Goodwill and Other Intangible Assets").  The key requirements of this Statement
include discontinuance of goodwill amortization, a revised framework for testing
goodwill  impairment  and new  criteria  for the  identification  of  intangible
assets.  Goodwill amortization in the gas distribution segment for the three and
six months  ended June 30,  2001 was $8.9  million and $17.8  million.  Goodwill
amortization for the twelve months ended December 31, 2001 was $35.6 million.

During the three  months  ended June 30,  2002,  we  recorded a  favorable  $7.4
million  adjustment  to  operating  taxes  related to the reversal of excess tax
reserves   established   for  the   KeySpan  /  LILCO   merger  and   subsequent
re-organization in May 1998.

Further contributing to the reduction in comparative operating expenses are cost
saving  synergies  currently  being  realized  primarily  as a  result  of early
retirement  and severance  programs  implemented  in the fourth  quarter of 2000
designed to reduce our  workforce  by  approximately  500  employees.  The early
retirement  portion of the  program was  completed  in 2000,  but the  severance
feature is expected to continue  through 2002.  Further,  the warmer than normal
weather  experienced  in the first  quarter of 2002  resulted in less repair and
maintenance work needed on our gas distribution infrastructure.

Other Matters

To take advantage of the anticipated gas sales growth  opportunities  in the New
York City metropolitan area, in 2000 we formed the Islander East Pipeline,  LLC,
a limited  liability  company in which a KeySpan  subsidiary and a subsidiary of
Duke Energy Corporation each own a 50% equity interest.  Islander East Pipeline,
LLC has received a positive  preliminary  determination  from the Federal Energy
Regulatory  Commission  ("FERC")  to  construct,  own and  operate a natural gas
pipeline facility consisting of approximately 50 miles of interstate natural gas
pipeline  extending  from  Algonquin Gas  Transmission  Company's  facilities in
Connecticut, across the Long Island Sound and connecting with KEDLI's facilities
on  Long  Island.  Subsequent  to the  timely  receipt  of  required  regulatory
approvals,  the Islander East  Pipeline is expected to begin  operating in 2003,
and 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. We are currently  evaluating
various  options for the financing of this pipeline.  (See the discussion  under
"Capital Expenditures and Financing" for more information on our financing plans
for 2002.)

<PAGE>

Electric Services

The Electric  Services segment  primarily  consists of subsidiaries that own and
operate oil and gas fired electric  generating  plants in Queens and Long Island
and,  through  long-term  contracts,   manage  the  electric   transmission  and
distribution ("T&D") system, the fuel and electric purchases, and the off-system
electric sales for the Long Island Power Authority ("LIPA").

Selected  financial data for the Electric  Services  segment is set forth in the
table below for the periods indicated.
<TABLE>
<CAPTION>
                                                                                                (In Thousands of Dollars)
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------

                                      Three Months Ended      Three Months Ended       Six Months Ended        Six Months Ended
                                        June 30, 2002           June 30, 2001           June 30, 2002           June 30, 2001
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
<S>                                              <C>                     <C>                    <C>                    <C>
 Revenues                                      $   354,781             $   357,929             $   669,489             $   701,325
 Purchased fuel                                     61,146                  74,327                 115,139                 153,654
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Net Revenues                                       293,635                 283,602                 554,350                 547,671
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Operating expenses
  Operations and maintenance                       183,936                 167,132                 332,056                 311,906
  Depreciation                                      13,928                  12,716                  27,661                  25,290
  Operating taxes                                   36,270                  38,365                  73,642                  81,669
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Total Operating Expenses                           234,134                 218,213                 433,359                 418,865
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Operating Income                                    59,501                  65,389                 120,991                 128,806
Other Income and (Deductions)                        5,218                   2,336                   9,373                   4,500
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Earnings Before Interest and Taxes             $    64,719             $    67,725             $   130,364             $   133,306
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Electric sales (MWH)*                            1,125,735               1,292,980               2,216,978               2,315,620
Capacity (MW)*                                       2,200                   2,200                   2,200                   2,200
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
</TABLE>
      *Reflects the operations of the Ravenswood facility only.

Net Revenues

Total  electric  net  revenues  increased  slightly for the three and six months
ended June 30, 2002, compared to the similar periods of 2001. Higher comparative
net  revenues  from the LIPA  service  agreements  were  mostly  offset by lower
comparative  net revenues from the Ravenswood  facility.  Revenues from the LIPA
service agreements  increased by $19.2 million,  or 10%, and by $32.1 million or
9% for the  quarter  and six months  ended June 30,  2002  compared  to the same
periods  last year.  Included in  revenues  for 2002,  are  billings to LIPA for
certain third party costs that were significantly higher than such billings last
year. These revenues generally have no impact on net income since we record a

<PAGE>

similar  amount of costs in  operating  expense.  Excluding  these  third  party
billings, revenues for the quarter and six months ended June 30, 2002 associated
with the LIPA service  agreements were comparable to such revenues earned during
the same period last year.

Net revenues  from the  Ravenswood  facility  were $10.5  million,  or 12% lower
during the three months ended June 30, 2002 compared to the same period in 2001,
primarily due to lower net revenues from capacity sales. Net revenues were $26.7
million, or 15% lower during the six months ended June 30, 2002, compared to the
same period in 2001. Net revenues from capacity sales were 12% lower compared to
the same period last year,  while margins  associated  with the sale of electric
energy were 22% lower than last year.  Comparative  energy sales were  adversely
impacted by a reduction in  "spark-spread"  combined with a decrease in electric
sales quantities as a result of a slight decrease in cooling degree days.

The  decrease in  comparative  net  revenues  from  capacity  sales for both the
quarter  and six  months  ended  June  30,  2002,  was  due,  in  part,  to more
competitive  pricing  by the  electric  generators  that  bid  into the New York
Independent  System Operator  ("NYISO") energy market and a revised  methodology
employed by the NYISO to assess the available supply of and demand for installed
capacity.

The rules and  regulations  for  capacity,  energy sales and the sale of certain
ancillary  services to the NYISO energy  markets are still evolving and the FERC
has adopted  several  price  mitigation  measures that have  adversely  impacted
comparative 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 can not fully be determined at this time.  (See our
Annual Report on Form 10K, Item 7A.  Quantitative  and  Qualitative  Disclosures
About Market Risk for a further discussion of these matters.)

The increase in net revenues  also  reflects  $1.2 million of revenues  from our
recently  constructed 79 megawatt  Glenwood  generating  facility that went into
operation on June 1, 2002.  The capacity of and energy  produced by the Glenwood
facility is dedicated to LIPA under long-term contract.

Operating Expenses

Operating expenses increased by $15.9 million, or 7% and by $14.5 million or 3%,
for the three and six months ended June 30, 2002, respectively,  compared to the
comparable  periods  last  year.  The  increase  in  operating  expenses  is due
primarily  to an increase in third party  costs.  We expect to incur  additional
third party costs for the remainder of the year. As previously mentioned,  these
costs are fully recovered from LIPA.

Other Income and Deductions

The increase of $2.8  million and $4.9 million in Other Income is due  primarily
to  inter-company  interest  income earned by  subsidiaries  within the Electric
Services segment.  For the most part, the various subsidiaries of KeySpan do not
maintain separate cash balances. Rather, liquid assets are maintained in a

<PAGE>

"central account", or Money Pool, from and to which subsidiaries can either
borrow or lend. Inter-company interest expense is charged to "borrowers", while
inter-company interest income is earned by "lenders". During the three and six
months ended June 30, 2002, the subsidiaries within the Electric Services
segment have been net "lenders" into the Money Pool and, accordingly, have
reflected inter-company interest income. Interest rates associated with money
pool borrowings are generally the same as KeySpan's short-term borrowing rate.
All inter-company interest income and expense is eliminated for consolidated
financial reporting purposes.

Other Matters

During  the  quarter,  we  also  completed  the  construction  of the 79 MW Port
Jefferson electric  generating  facility on Long Island and placed this facility
in service on July 1, 2002. This facility is under a 25 year capacity and energy
contract with LIPA. We used  short-term  financing for the  construction  of the
Glenwood  and  Port  Jefferson  generating  facilities,  but  we  are  currently
exploring  various  financing  options to permanently  finance these facilities.
(See  the  discussion  under  "Capital  Expenditures  and  Financing"  for  more
information on our financing  plans for 2002.)  Further,  in June 2002, we began
construction  of 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 our  proposal to build a similar  250 MW  combined  cycle
electric generating facility on Long Island.

Under the Generation Purchase Right Agreement ("GPRA"), LIPA had the right for a
one-year  period,  beginning on May 28, 2001,  to acquire all of our Long Island
based generating assets formerly owned by LILCO at fair market value at the time
of the  exercise of such right.  By  agreement  dated March 29,  2002,  LIPA and
KeySpan  amended the GPRA to provide for a new six month option period ending on
May 28,  2005.  The other  terms of the option  reflected  in the GPRA  remained
unchanged.

In return for  providing  LIPA an extension  of the GPRA,  KeySpan and LIPA have
agreed to an extension for 31 months of the Management  Services Agreement under
which  KeySpan  manages  the  day-to-day  operations,  maintenance  and  capital
improvements of LIPA's  transmission and distribution  system. The extension has
received the approval of the New York State Public Authorities Control Board and
the State Controller.

The extensions  are the result of a new  initiative  established by LIPA to work
with KeySpan and others to review Long Island's long-term energy needs. LIPA and
KeySpan will jointly  analyze new energy supply  options  including  re-powering
existing  plants,   renewable  energy  technologies,   distributed   generation,
conservation initiatives and retail competition.  The extension allows both LIPA
and KeySpan to explore  alternatives to the GPRA including  re-powering existing
facilities,  the sale of some or all of KeySpan's plants to LIPA, or the sale of
some or all of these plants to other private operators.

<PAGE>

Energy Services

The Energy Services segment primarily  includes  companies that provide services
through  three  lines of business  to clients  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.
<TABLE>
<CAPTION>
                                                                                                (In Thousands of Dollars)
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------

                                      Three Months Ended      Three Months Ended       Six Months Ended        Six Months Ended
                                        June 30, 2002           June 30, 2001           June 30, 2002           June 30, 2001
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
<S>                                              <C>                    <C>                      <C>                     <C>
Revenues                                       $   229,311             $   232,771             $   470,870             $   551,864
Less: cost of gas and fuel                          45,731                  91,892                 111,885                 245,175
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Net revenues                                       183,580                 140,879                 358,985                 306,689
Other operating expenses                           194,447                 198,237                 379,209                 370,859
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Operating  Loss                                   (10,867)                (57,358)                (20,224)                (64,170)
Other Income and (Deductions)                          615                     318                     775                     751
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Loss Before Interest and Taxes                $   (10,252)             $  (57,040)            $   (19,449)            $   (63,419)
----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
</TABLE>

Comparative EBIT results for the three and six months ended June 30, 2002 verses
the comparable periods last year were significantly  impacted by losses incurred
by one of our  subsidiaries.  In 2001, we discontinued  the general  contracting
activities  related to the  former  Roy Kay  companies,  with the  exception  of
completion of work on existing  contracts,  based upon our view that the general
contracting  business  is not a core  competency  of these  companies.  (See our
Annual  Report  on  Form  10K  for the  year  ended  December  31,  2001  Item 7
"Management's  Discussion of Financial  Condition and Results of Operations" and
Note 11 to those  Consolidated  Financial  Statements  "Roy Kay Operation" for a
more detailed  discussion.) For the three and six months ended June 30, 2001, we
incurred  EBIT  losses  of  $53.3  million  and  $61.2  million,   respectively,
associated  with  the  operations  of  the  former  Roy  Kay  companies.  We are
completing  the contracts  entered into by the former Roy Kay companies and, for
the three and six months  ended June 30, 2002,  we incurred  EBIT losses of $1.8
million and $3.3 million,  respectively  reflecting overhead, and administrative
and general expenses. These costs could not be accrued in 2001.

Excluding  the  results  of the former Roy Kay  companies,  the Energy  Services
segment  reflected a decrease in EBIT of $4.6 million and $13.9  million for the
three  and  six  months  ended  June  30,  2002,  respectively  compared  to the
corresponding  periods last year.  Revenues,  excluding  the Roy Kay  companies,
decreased by $45.7 million and $144.1 million for the three and six months ended
June 30, 2002,  respectively,  while the cost of fuel decreased by $46.2 million
and $133.3 million during the same time periods. These decreases,  which for the
most part offset each other,  reflect  the  operations  of our gas and  electric
marketing company. Beginning in 2002, we focused our marketing efforts on higher
net margin customers and as a result we have decreased our customer base.

<PAGE>

EBIT results have been adversely impacted in 2002 by the general  "down-turn" in
the New York  metropolitan  economy.  In addition,  the  extremely  warm weather
during the winter  heating  season has reduced  the number of service  calls and
repair  orders  received.  Further,  during the  quarter  ended June 30, 2002 we
increased our reserve for bad debts. We are currently  re-aligning / combining a
number of our service  centers in this segment in order to reduce  operating and
general  and  administrative  costs,  as well  as to  realize  synergy  savings.
Comparative  EBIT  results  for the three and six  months  ended  June 30,  2002
benefited from the elimination of goodwill amortization, which for the three and
six months  ended June 30,  2001  amounted  to $2.1  million  and $4.2  million,
respectively.

Energy Investments

The Energy  Investment  segment  consists of our gas  exploration and production
operations 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 67%
equity interest in Houston Exploration,  as well as our wholly-owned subsidiary,
KeySpan Exploration and Production, LLC.

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

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>
                                                                                                         (In Thousands of Dollars)
----------------------------------------- --------------------- --------------------- ----------------------- ----------------------

                                            Three Months Ended      Three Months Ended     Six Months Ended        Six Months Ended
                                              June 30, 2002           June 30, 2001          June 30, 2002           June 30, 2001
----------------------------------------- --------------------- --------------------- ---------------------- -----------------------
<S>                                                   <C>                 <C>                     <C>                     <C>
Revenues                                           $    88,274           $   103,720            $   162,988             $   235,731
Depletion and amortization expense                      44,440                33,419                 85,885                  67,052
Other operating expenses                                14,379                13,282                 27,823                  32,444
----------------------------------------- --------------------- --------------------- ---------------------- -----------------------
Operating Income                                        29,455                57,019                 49,280                 136,235
Other Income and (Deductions)*                         (5,860)              (13,062)               (10,013)                (26,762)
----------------------------------------- --------------------- --------------------- ---------------------- -----------------------
Earnings Before Interest and Taxes*                $    23,595           $    43,957            $    39,267             $   109,473
----------------------------------------- --------------------- --------------------- ---------------------- -----------------------
Natural gas and oil production (Mmcf)                   26,251                22,904                 51,921                  46,681
Natural gas price (per Mcf) realized                     $3.19                 $4.54                  $3.04                   $5.05
Natural gas price  (per Mcf) unhedged                    $3.19                 $4.49                  $2.70                   $5.69
Proved reserves at year-end (BCFe)                         647                   593                    647                     593
----------------------------------------- --------------------- --------------------- ---------------------- -----------------------
</TABLE>

*Operating  income above  represents  100% of our gas exploration and production
subsidiaries'  results for the periods  indicated.  Earnings before interest and
taxes,  however,  is adjusted to reflect  minority  interest.  Gas  reserves and
production are stated in BCFe and Mmcfe, which includes equivalent oil reserves.

<PAGE>

Earnings Before Interest and Taxes

The decreases in EBIT of $20.4 million, or 46% and $70.2 million, or 64% for the
three  and six  months  ended  June  30,  2002,  respectively,  compared  to the
corresponding  periods last year,  reflects a  significant  decrease in revenues
and, to a lesser  degree,  an increase in  operating  expenses  associated  with
higher  production  volumes.  Revenues for the quarter and six months ended June
30, 2002,  compared to the same periods in 2001, were adversely  impacted by the
significant  decline in average  realized  gas prices  (average  wellhead  price
received for production  including  realized hedging gains and losses).  Average
realized gas prices  decreased  30% and 40% for the quarter and six months ended
June 30, 2002,  respectively,  compared to the corresponding  periods last year.
The adverse effect on revenues  resulting  from the decline in average  realized
gas  prices  was  partially  offset by  increases  of 15% and 11% in  production
volumes  during the quarter and six months  ended June 30,  2002,  respectively,
compared  to the  same  periods  last  year.  The  depreciation,  depletion  and
amortization  rate was  $1.65 per mcf for the six  months  ended  June 30,  2002
compared to $1.47 for the same period in 2001, as a result of higher finding and
development costs together with the addition of fewer new reserves.

The average realized gas price in the second quarter of 2002 was the same as the
average  unhedged natural gas price and was 113% of the average unhedged natural
gas price for the six months ended June 30, 2002. The average realized gas price
in the second quarter of 2001 was 101% of the average unhedged natural gas price
and was 89% of the average  unhedged  natural gas price for the six months ended
June 30, 2001. Houston Exploration  entered into derivative  financial positions
in 2001 to hedge a substantial portion of its anticipated 2002 production. 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.  The  settlement  of derivative  instruments  during the six
months ended June 30, 2002  resulted in a benefit to revenues of $17.0  million.
(See Note 6 to the  Consolidated  Financial  Statements,  "Derivative  Financial
Instruments" for further  information.)

Natural gas prices continue to fluctuate and the risk that we may be required to
write-down  our investment in exploration  and production  properties  increases
when  natural  gas  prices  are  depressed  or if we have  significant  downward
revisions in our estimated proved reserves.

At December 31, 2001, our gas  exploration and production  subsidiaries  had 647
BCFe of net proved  reserves  of natural  gas, of which  approximately  72% were
classified as proved developed.

Selected financial data and operating statistics for our other energy-related
investments are set forth in the following table for the periods indicated.
<TABLE>
<CAPTION>
                                                                                                    (In Thousands of Dollars)
------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------

                                        Three Months Ended      Three Months Ended       Six Months Ended        Six Months Ended
                                          June 30, 2002           June 30, 2001           June 30, 2002           June 30, 2001
------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------
<S>                                                 <C>                     <C>                     <C>                     <C>
Revenues                                          $   21,942              $   24,222              $   39,575             $    51,191
Operation and maintenance expense                     19,768                  15,871                  33,826                  33,136
Other operating expenses                               5,545                   4,019                   8,572                   7,782
------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------
Operating Income (Loss)                              (3,371)                   4,332                 (2,823)                  10,273
Other Income and (Deductions)                          4,637                   2,816                   8,982                   6,128
------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------
Earnings Before Interest and Taxes                $    1,266              $    7,148              $    6,159             $    16,401
------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------
</TABLE>


Decreases in EBIT of $5.9  million,  or 82%, and $10.2  million,  or 62% for the
three and six months ended June 30, 2002 are primarily due to the  operations of
KeySpan Canada,  losses incurred by certain  technology-related  investments and
lower earnings from our liquefied natural gas ("LNG") transportation subsidiary.
KeySpan  Canada  experienced  lower  per  unit  sales  prices,  as well as lower
quantities of sales of natural gas liquids in both periods of 2002,  compared to
the same periods in 2001, as a result of generally lower oil prices. The pricing
of natural gas liquids is directly related to oil prices. Our LNG transportation
subsidiary  realized  lower EBIT results for both the three and six months ended
June 30,  2002  compared  to the same  periods  last year,  as a result of lower
demand for LNG due to the extremely warm weather.

<PAGE>

We do not consider the 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.  Based on current
market conditions,  we can not predict when, or if, any such sale or disposition
may take place,  or the effect that any such sale or disposition may have on our
financial position, results of operations or cash flows.

Liquidity

The  increase  in cash flow from  operations  for the six months  ended June 30,
2002, compared to the corresponding period last year, is primarily  attributable
to lower  interest and income tax payments.  As previously  mentioned,  interest
payments have  decreased due to the use of derivative  financial  instruments to
hedge a portion of our  exposure  to  interest  rate  risk,  as well as to lower
interest rates on outstanding  commercial paper. Further, in terms of cash flow,
state and  federal  tax  payments  were  lower for the first six  months of 2002
compared  to the same  period  last  year,  since we are  currently  in a refund
position  with  regards  to  such  taxes.  Operating  cash  flow  from  our  gas
exploration  and  production  activities,  however,  was  adversely  impacted by
significantly  lower  realized  gas  prices  for the  first  six  months of 2002
compared to the same period last year. (See Note 6 to the Consolidated Financial
Statements "Derivative Financial Instruments" for an explanation of the interest
rate hedges.)

As previously indicated, a substantial portion of our consolidated revenues are
derived from the operations of businesses within the Electric Services Segment,
that are dependent upon two large customers - LIPA and the NYISO. According, our
cash flows are dependent upon the timely payment of amounts owed to us by these
customers.

In July 2002, we renewed our existing 364-day  revolving credit agreement with a
commercial  bank syndicate of 16 banks  totaling $1.3 billion,  a reduction from
the previous $1.4 billion  facility.  The credit facility is used to back up our
current $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,  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 borrow on the credit facility.

At June 30, 2002, we had cash and temporary cash  investments of $137.6 million.
During  the six  months  ended  June 30,  2002,  we  repaid  $477.8  million  of
commercial  paper and, at June 30, 2002,  $570.7 million of commercial paper was
outstanding at a weighted average annualized  interest rate of 1.93%. We had the
ability to borrow up to an additional  $829.3 million at June 30, 2002 under our
commercial paper program.

Under the terms of the credit facility,  our debt-to-total  capitalization ratio
will reflect 80% equity  treatment for the MEDS Equity Units issued in May 2002;
further the $425 million  Ravenswood  Master Lease will be treated as debt.  The
financial  covenant  in the credit  facility  reflects  a maximum  debt-to-total
capitalization  ratio of 66%, a decrease from the 68% ratio  required  under the
previous credit facility.  At June 30, 2002, our consolidated  indebtedness,  as
calculated  under  the  terms  of the new  credit  facility,  was  63.1%  of our
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 "Capital  Expenditures  and Financing for an
explanation of the MEDS Equity Units.)

<PAGE>

On July 15,  2002,  Houston  Exploration  entered  into a new  revolving  credit
facility  with a commercial  banking  syndicate  that replaces the existing $250
million revolving credit facility. The new facility provides Houston Exploration
with an initial  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 new credit  facility is subject to borrowing  base  limitations,
initially set at $300 million and will be re-determined semi-annually,  with the
first re-determination scheduled for October 1, 2002. Up to $25.0 million of the
borrowing  base is  available  for the  issuance  of letters of credit.  The new
credit  facility  matures  July 15, 2005,  is unsecured  and ranks senior to all
existing debt.

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 .5% 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  loans is payable  at a fixed rate equal to the sum of (a) a quoted  LIBOR
rate divided by one minus the average  maximum  rate during the interest  period
set for  certain  reserves  of member  banks of the  Federal  Reserve  System in
Dallas,  Texas 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,
maintain:  (i) an interest  coverage  ratio of at least 3.00 to 1.00 of earnings
before interest,  taxes and depreciation to cash interest (EBITDA); (ii) a total
debt to  EBITDA  of not  more  than a ratio of 3.50 to 1.00;  and  (iii)  sets a
maximum limit of 70% on the amount of natural gas production  that may be hedged
during any 12-month period.

During the six months ended June 30, 2002,  Houston  Exploration  borrowed $46.0
million under its prior credit  facility and repaid $10.0  million.  At June 30,
2002,  $180 million of borrowings  remained  outstanding  at a weighted  average
annualized  interest  rate of 3.23%;  $70.0  million of  borrowing  capacity was
available. Also, KeySpan Canada has two revolving loan agreements with financial
institutions in Canada.  Repayments under these agreements totaled approximately
$26.4  million  for the six  months  ended  June 30,  2002.  At June  30,  2002,
approximately  $157 million was  outstanding  at a weighted  average  annualized
interest rate of 3.05%.  KeySpan  Canada  currently has available  borrowings of
approximately $57 million.

KeySpan has fully and  unconditionally  guaranteed  $525 million of medium- term
notes issued by KEDLI under  KEDLI's  current shelf  registration,  as well as a
$130  million   revolving   credit   agreement   associated  with  its  Canadian
subsidiaries.  Both the  medium-term  notes  and  borrowings  under  the  credit
agreement are reflected on the Consolidated Balance Sheet.

<PAGE>

Further,  KeySpan has guaranteed:  (i) $160.8 million of 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 in the aggregate amount of
$85.3 million; (iii) the obligations of KeySpan Ravenswood LLC, the lessee under
the $425  million  Master  Lease  Agreement  associated  with  the  lease of the
Ravenswood  facility;  and (iv) $59.7 million of  subsidiary  letter of credits.
These  guarantees  are not  recorded  on the  Consolidated  Balance  Sheet.  The
guarantee  of the KEDLI  medium-  term notes  expires  in 2010,  while the other
guarantees  have terms that do not extend beyond 2005;  however the Master Lease
Agreement  can be extended to 2009.  At this point in time, we have no reason to
believe  that  our  subsidiaries  will  default  on their  current  obligations.
However, we can not 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 the discussion of the  Ravenswood  lease under the
heading  "Capital  Expenditures  and Financing" for a description of the leasing
arrangement.

We  satisfy  our  seasonal  working  capital   requirements   primarily  through
internally generated funds and the issuance of commercial paper. In addition, we
realized  $174.5  million in proceeds from the sale of Midland.  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 employee common stock, dividend reinvestment and benefit plans.

Capital Expenditures and Financing

Construction Expenditures

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

                                             (In Thousands of Dollars)
------------------------------- ----------------------- -----------------------

                                   Six Months Ended        Six Months Ended
                                    June 30, 2002           June 30, 2001
------------------------------- ----------------------- -----------------------
Gas Distribution                           $   183,588             $   120,874
Electric Services                              225,051                  99,196
Energy Investments                             176,755                 198,612
Energy Services                                 10,109                   6,125
------------------------------- ----------------------- -----------------------
                                           $   595,503             $   424,807
------------------------------- ----------------------- -----------------------

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 the new Long Island  generating
facilities as previously noted.  Construction expenditures related to the Energy
Investments  segment primarily reflect costs associated with our gas exploration
and  production  activities.  These  costs are  related  to the  development  of
properties   primarily  in  Southern  Louisiana  and  in  the  Gulf  of  Mexico.
Expenditures  also include  development  costs associated with our joint venture
with Houston Exploration, as well as costs related to Canadian affiliates.

<PAGE>

At June 30, 2002, 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 are
$162.6 million.

The amount of future  construction  expenditures is reviewed on an ongoing basis
and can be affected by timing, scope and changes in investment opportunities.

Financing

At December 31, 2001, we had an existing $1 billion shelf registration statement
on file with the Securities and Exchange Commission  ("SEC"),  with $500 million
available for issuance.  In February 2002, we updated our shelf registration for
the issuance of an additional $1.2 billion of securities,  thereby giving us the
ability  to issue  up to $1.7  billion  of  debt,  equity  or  various  forms of
preferred stock. At December 31, 2001, we had authority under the Public Utility
Holding Company Act ("PUHCA") to issue up to $1 billion of this amount.

On April  30,  2002,  we  issued  $460  million  of MEDS  Equity  Units at 8.75%
consisting of a three-year  forward purchase contract for our common stock and a
six-year  note.  The purchase  contract  commits us three years from the date of
issuance  of the MEDS  Equity  Units to issue and the  investors  to  purchase a
number of shares of our common stock based on a formula tied to the market price
of our common  stock at that time.  The 8.75%  coupon is  composed  of  interest
payments on the  six-year  note of 4.9% and premium  payments on the  three-year
equity  forward  contract  of 3.85%.  These  instruments  have been  recorded as
long-term debt on our Consolidated  Balance Sheet, but rating agencies  consider
between 80% to 100% of the  instruments  as equity for  purposes of  calculating
debt-to-total  capitalization  ratios. (See Note 5 to the Consolidated Financial
Statements "Long-Term Debt" for further details on the MEDS Equity Units).

The issuance of the MEDS equity  units  utilized  $920 million of our  financing
authority under both the shelf  registration and the PUHCA financing  authority.
Both the $460 million six-year note and the $460 million forward equity contract
are considered  current  issuances for these purposes.  Therefore,  we have $780
million  available  for issuance  under the shelf  registration  and $80 million
available under PUHCA. We have filed an amendment to our financing authorization
with the SEC to increase our  financing  authority  under PUCHA by $700 million,
thereby matching our shelf availability. We anticipate action on this request by
the SEC this year.

In May 2002, Colonial Gas Company repaid $15 million of its 6.81% Series A First
Mortgage Medium -Term Notes. These Notes would have matured on May 19, 2027, but
the  holder of the Notes  elected  to  exercise a put option to redeem the Notes
early.

As previously  noted, we issued  commercial paper to finance the construction of
our two Long Island  peaking-power  plants,  and we will continue to finance the
construction  of  the  new  250MW  combined  cycle  generating  facility  at the
Ravenswood  facility  site, as well as the Islander East  Pipeline,  through the
issuance of commercial paper.

<PAGE>

By the end of 2002,  we intend to issue  approximately  $150 to $200  million of
either  taxable or  tax-exempt  debt  securities,  the proceeds of which,  it is
anticipated,  will be used to re-pay the outstanding commercial paper related to
the construction of our two Long Island peaking-power  plants. We also may issue
additional  medium-term  or  long-term  debt  towards the latter part of 2002 to
replace  outstanding  commercial paper, if market  conditions are favorable.  We
will continue to evaluate our capital structure and financing  strategy for 2002
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 sale
of Midland, are sufficient to meet our anticipated working capital needs for the
foreseeable future.

As noted,  as part of our strategy to maintain an optimal level of floating rate
debt, we have several interest rate swap agreements on a portion of our existing
fixed rate  medium-term and long-term debt that  effectively  change the debt to
floating rate debt. These swap agreements  qualify for hedge accounting and were
completed with several major  financial  institutions  in order to reduce credit
risk. (See Note 6 to the Consolidated Financial Statements "Derivative Financial
Instruments" for additional information on these swap agreements.)

We also have an  arrangement  with a special  purpose  financing  entity through
which we lease a portion of the Ravenswood facility.  We acquired the Ravenswood
facility  from  Consolidated  Edison  on June 18,  1999 for  approximately  $597
million.  In order to reduce our initial  cash  requirements,  we entered into a
lease  agreement  with a special  purpose,  unaffiliated  financing  entity that
acquired a portion of the facility directly from Consolidated  Edison and leased
it to our subsidiary. We have guaranteed all payment and performance obligations
of our  subsidiary  under the lease.  The 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 special
purpose  financing entity not been utilized and conventional debt financing been
employed.  Further, we would have recorded an asset in the same amount.  Monthly
lease payments  represent  interest  only.  The lease  qualifies as an operating
lease for financial  reporting  purposes  while  preserving our ownership of the
facility for federal and state income tax purposes.

The initial term of the lease expires on June 20, 2004 and may be extended until
June 20, 2009. In June 2004,  we have the right to either  purchase the facility
or terminate the lease and dispose of the facility for an amount generally equal
to the original  acquisition  cost, $425 million,  plus the present value of the
lease  payments  that would have  otherwise  been paid through June 20, 2009. In
June 2009, when the lease terminates,  we may purchase the facility in an amount
generally  equal to the original  acquisition  cost or surrender the facility to
the lessor.  At this time,  we believe  that the fair market value of the leased
assets is in excess of the original acquisition cost.

The Financial  Accounting  Standards Board (the "Board") is currently  reviewing
issues  related to special  purpose  entities and in May 2002 issued an Exposure
Draft regarding the accounting for, and disclosure of special purpose  entities.
It is expected that the final  guidance will be issued in 2002, and be effective
January 1, 2003.  It is possible  that we may be required to classify  the lease
under which we operate the Ravenswood  facility as approximately $425 million of
indebtedness

<PAGE>

and  reflect  such  amount on our  Consolidated  Balance  Sheet.  As  previously
mentioned,  under the terms of our new credit  facility  the  Ravenswood  Master
Lease  is  currently   considered   as  debt  in  the  ratio  of   debt-to-total
capitalization.  At this  time,  however,  we are unable to  determine  what the
requirements  will be  under  the  final  guidance,  if and  when an  accounting
Standard is issued,  as well as the actual  impact on our results of  operations
and financial position.

The ratings on our  long-term  debt have  remained  unchanged  from December 31,
2001.  Moody's Investor Services rated: (i) KeySpan's  long-term debt at A3; and
(ii) KEDNY's, KEDLI's, Boston Gas Company's and Colonial Gas Company's long-term
debt at A2.  Standard and Poor's rating agency rated:  (i) the long-term debt of
KeySpan,  KeySpan Generation,  Boston Gas Company and Colonial Gas Company at A;
and (ii) KEDNY's and KEDLI's long-term debt at A+.

Our contractual cash  obligations and associated  maturities have increased from
December  31,  2001 due to the  issuance  of the MEDS  Equity  Units  previously
discussed.

The table below reflects maturity schedules for our cash contractual obligations
at June 30, 2002:
<TABLE>
<CAPTION>
                                                                                                           (In Thousands of Dollars)
---------------------------------------- ------------------- --------------------- ----------------------- -------------------------

Contractual Obligations                           Total              1-3 Years              4-5 Years               After 5 Years
---------------------------------------- ------------------- --------------------- ----------------------- -------------------------
<S>                                            <C>                    <C>                  <C>                         <C>
Long-Term Debt                           $      5,263,490    $           486,184   $          1,212,333    $             3,564,973

Capital Lease Obligations                          14,969                  2,826                  2,163                      9,980

Operating Leases                                  633,313                261,953                165,441                    205,919
---------------------------------------- ------------------- --------------------- ----------------------- -------------------------

Total Contractual
   Cash Obligations                      $      5,911,772    $           750,963   $          1,379,937    $             3,780,872
---------------------------------------- ------------------- --------------------- ----------------------- -------------------------

Commercial Paper                         $        570,655              Revolving
---------------------------------------- ------------------- --------------------- ----------------------- -------------------------
</TABLE>

<PAGE>

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 judgements  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  our  estimates  prove to be  inaccurate.  The  critical
accounting policies requiring such subjectivity are discussed below.

Percentage of Completion Accounting

Significant  reliance is placed upon  estimates of future job costs in computing
revenue and subsequent  net income under the percentage of completion  method of
revenue  recognition  for the designing,  building and  installation of heating,
ventilation and air-conditioning  systems by subsidiaries in our Energy Services
segment.  This  accounting  method measures the percentage of costs incurred and
accrued to date for each contract to the estimated total costs for each contract
at completion.  These estimates are based upon available information at the time
of review,  and changes in  estimates  resulting in  additional  future costs to
complete  projects can result in reduced margins or loss  contracts.  Provisions
for estimated losses on uncompleted contracts are made in the period such losses
are  determined.  Changes  in job  performance,  job  conditions  and  estimated
profitability are recognized in the period that the revisions are determined.

Valuation of Goodwill

On January 1, 2002, we adopted SFAS 141, "Business  Combinations",  and SFAS 142
"Goodwill  and  Other  Intangible  Assets".   The  key  concepts  from  the  two
interrelated  Statements  include  mandatory  use of the  purchase  method  when
accounting for business combinations, discontinuance of goodwill amortization, a
revised  framework for testing goodwill  impairment at a "reporting unit" level,
and new criteria for the  identification  and  potential  amortization  of other
intangible assets.

Other changes to existing  accounting  standards  involve a requirement  to test
goodwill for impairment at least annually.  The initial impairment test is to be
performed  within six months of adopting  SFAS 142 using a discounted  cash flow
method,  compared to a  undiscounted  cash flow method  allowed under a previous
standard. Any amounts impaired using data as of January 1, 2002 will be recorded
as a "Cumulative  Effect of an Accounting  Change".  Any amounts  impaired using
data after the initial adoption date will be recorded as an operating expense.

We  record  goodwill  on  purchase  transactions,  representing  the  excess  of
acquisition  cost over the fair value of net  assets  acquired.  In testing  for
goodwill  impairment  under  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 many 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
will likely differ from our projections.



<PAGE>



We  have  completed  our  analysis  for  all of our  reporting  units  and  have
determined  that  no  consolidated  impairment  exists.  This  determination  of
impairment  was done at the  reporting  unit level,  which we  considered  to be
virtually the same as our financial reporting  segments.  In the future, we will
conduct  an  annual  review  of  our  investments  to  determine  if  events  or
circumstances  warrant new  appraisals  to be  conducted to support the carrying
value of our assets.

Valuation of Derivative Instruments

We employ derivative instruments to hedge a portion of our exposure to commodity
price risk and interest rate risk, as well as to hedge the cash flow variability
associated  with a portion of our  electric  energy  sales  from the  Ravenswood
facility. 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.  However,  the oil derivative
instruments  we employ to hedge the purchase  price on a portion of the oil used
to fuel  the  Ravenswood  facility  are not  exchange  traded.  We use  industry
published  oil  indices  for No.  6 grade  fuel  oil to  value  these  oil  swap
contracts.

As mentioned,  we also engage in the use of derivative  instruments to hedge the
cash flow  variability  associated  with a portion of our electric  energy sales
from the Ravenswood  facility.  In addition,  our Canadian  subsidiary uses swap
instruments to lock-in the purchase price on the purchase of electricity  needed
to operate its gas processing  plants.  These arrangements are also non-exchange
traded and we use NYISO-location zone and other local published indices to value
these outstanding  derivatives.  For collar transactions relating to natural gas
sales  associated with our gas exploration and production  subsidiaries,  we use
standard  NYMEX quotes,  as well as Black-  Scholes  valuations to calculate the
fair value of these instruments.

Finally,  we also have interest rate swap agreements in which approximately $1.3
billion of fixed rate debt has been effectively converted to floating rate debt.
The fair value of these derivative  instruments is provided to us by third party
appraisers and represents the present value of estimated future cash-flows based
on a forward interest rate curve for the life of the derivative instrument.

All fair value  measurements,  whether calculated using standard NYMEX quotes or
other  valuation  techniques,  are  subjective  and subject to  fluctuations  in
commodity prices,  interest rates and overall economic market conditions and, as
a result,  our fair  value  measurements  may not be precise  and can  fluctuate
significantly from period to period.  (See Note 6 to the Consolidated  Financial
Statements  "Derivative Financial  Instruments" for a further description of the
instruments.)



<PAGE>



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 our
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.  A  write-down  of the  carrying  value of the full cost pool is a
non-cash charge that reduces  earnings and impacts  stockholders'  equity in the
period of occurrence and typically results in lower depreciation,  depletion and
amortization  expense in future  periods.  Once  incurred,  a write-down  is not
reversible at a later date.

The ceiling test is calculated  using natural gas and oil prices in effect as of
the balance sheet date,  held  constant  over the life of the reserves.  Our gas
exploration and production  subsidiaries  use derivative  financial  instruments
that  qualify for hedge  accounting  under  Statement  of  Financial  Accounting
Standards  ("SFAS")  No. 133 to hedge  against  the  volatility  of natural  gas
prices.  In  accordance  with  current SEC  guidelines,  these  derivatives  are
included in the estimated future cash flows in the ceiling test calculation.  In
calculating the ceiling test at June 30, 2002, our subsidiaries estimated that a
full cost ceiling "cushion" existed, whereby the carrying value of the full cost
pool was less that the ceiling  limitation.  No  writedown  is  required  when a
cushion exists.  Natural gas prices continue to be volatile and the risk that we
will be required  to write down the full cost pool  increases  when  natural gas
prices are depressed or if there are significant downward revisions in estimated
proved reserves.

Natural gas and oil reserve quantities  represent  estimates only. Any estimates
of natural  gas and oil  reserves  and their  values are  inherently  uncertain,
including many factors beyond our control.  The accuracy of any reserve estimate
is a function of the quality of available data and of engineering and geological
interpretation and judgment.  In addition,  estimates of reserves may be revised
based upon actual  production,  results of future  development  and  exploration
activities,  prevailing  natural gas and oil prices,  operating  costs and other
factors, which revision may be material.  Reserve estimates are highly dependent
upon the accuracy of the underlying assumptions. Actual future production may be
materially different from estimated reserve quantities and the differences could
materially affect future amortization of natural gas and oil properties.

Accounting for the Effects of Rate Regulation on Gas Distribution Operations

The  accounting  records for our six regulated  gas utilities are  maintained in
accordance with the Uniform System of Accounts  prescribed by the Public Service
Commission of the State of New York ("NYPSC"),  the New Hampshire Public Utility
Commission,  and the Massachusetts  Department of Telecommunications  and Energy
("DTE").

<PAGE>

Our financial  statements  reflect the  ratemaking  policies and orders of these
regulators in conformity  with  generally  accepted  accounting  principles  for
rate-regulated  enterprises.  Four of our six regulated  gas  utilities  (KEDNY,
KEDLI,  Boston Gas Company and EnergyNorth Natural Gas, Inc.) are subject to the
provisions  of  Statement  of  Financial   Accounting   Standards  ("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.

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. Due to the length of these base rate freezes,  the
Colonial and Essex Gas Companies had previously  discontinued the application of
SFAS 71.

As is further  discussed under the caption  "Regulation  and Rate Matters",  the
rate plans currently in effect for KEDNY,  KEDLI and Boston Gas Company will all
have expired by October 31, 2002. The continued application of SFAS 71 to record
the  activities  of  these  subsidiaries  is  contingent  upon  the  actions  of
regulators  with  regards to future  rate  plans.  We are  currently  evaluating
various  options  that may be  available  to us  including  but not  limited to,
extending  the  existing  rate  plans  or  proposing  new  plans.  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.


Regulation and Rate Matters

Gas Matters

On March  27,  2002,  we  filed  notice,  as  required,  with the  Massachusetts
Department of Telecommunications and Energy ("DTE") that we may file a base rate
case and a performance based rate plan for the Boston Gas Company to replace the
current plan that expires on October 31,  2002.  On May 21, 2002,  we filed with
the DTE a request  to extend  the  existing  performance  based rate plan for an
additional term of one year. The Massachusetts  Attorney General has submitted a
letter  to the DTE  stating  his  opposition  to our  request.  Our  request  is
currently pending before the DTE.

<PAGE>

The rate agreement for KEDLI expired in November 2001 and the rate agreement for
KEDNY expires  September 30, 2002. The New Hampshire  Public Utility  Commission
has indicated that they may examine the cost  structure of  EnergyNorth  Natural
Gas during 2002. At this time, we are currently  evaluating various options that
may be available to us including but not limited to, extending the existing rate
plans or proposing new rate plans.

For additional  discussion of our current gas distribution rate agreements,  see
our Annual  Report on Form 10-K for the year ended  December  31,  2001,  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,  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 $5.1 billion,  (i) maintain existing financing
agreements,  (ii) issue and sell up to $1.5 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, review,  extend,
supplement or replace any of the foregoing;  (b) issue shares of common stock or
reissue shares of common 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 250% of our consolidated  retained earnings in exempt wholesale
generators and foreign utility  companies;  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.  As previously indicated, we have
filed an application  with the SEC seeking  authority to issue and sell up to an
aggregate $2.2 billion of additional  securities,  as well as  authorization  to
invest up to an aggregate $2.2 billion in exempt wholesale generators.

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 June 30, 2002 our consolidated  common equity was 34% of our
consolidated capitalization, including commercial paper.



<PAGE>



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  $207.0 million
and we have recorded a related  liability for such amount. We have also recorded
an additional $41.8 million liability,  representing the estimated environmental
cleanup costs related to a former coal tar processing  facility.  Further, as of
June 30, 2002,  we have  expended a total of $54.0  million.  (See Note 4 to the
Consolidated Financial Statements, "Environmental Matters").


Cautionary Statement Regarding Forward-Looking Statements

Certain  statements  contained in this Quarterly  Report on Form 10-Q 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.

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

-    volatility of energy prices, as well as natural gas and fuel prices 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;

-    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;

-    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;

<PAGE>


-    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;

-    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

We  are  subject  to  various  risks  and  uncertainties   associated  with  our
operations.  The most  significant  of which  involves the  evolution of the gas
distribution and electric  industries towards a more competitive and deregulated
environment.  In addition, we are exposed to commodity price risk, interest rate
risk and, to much less degree,  foreign currency  translation  risk. Below is an
update of the various risks  associated with our operations.  Additionally,  see
our  Annual  Report on Form 10K for the year  ended  December  31,  2001 Item 7A
"Quantitative and Qualitative Disclosures About Market Risk".

Regulatory Issues and Competitive Environment

Gas Distribution

On May 23, 2002, the NYPSC issued an Order  Adopting Terms of Gas  Restructuring
Joint Proposal  Petition of KeySpan Energy  Delivery New York and KeySpan Energy
Delivery  Long  Island  for  a  Multi-Year   Restructuring   Agreement   ("Joint
Proposal"). The Joint Proposal did not alter base rate levels, but established a
merchant  function  backout  credit of $.21/dth and $.19/dth for KeySpan  Energy
Delivery New York and KeySpan Energy Delivery Long Island,  respectively.  These
credits are designed to lower  transportation  rates  charged to  transportation
only  customers.  These  credits were based on  established  levels of projected
avoided costs and levels of customer migration to non-utility commodity service.
Lost revenues resulting from application of these credits will be recovered from
firm gas sales customers.

<PAGE>

Electric Industry

The Ravenswood Facility and our New York City Operations

The NYISO's New York City local  reliability rules currently require that 80% of
the  electric  capacity  needs  of  New  York  City  be  provided  by  "in-City"
generators. As additional, more efficient electric power plants are built in New
York City and the surrounding areas, the requirement that 80% of in-City load be
served by in-City generators could be modified. Construction of new transmission
facilities  could also cause  significant  changes to the market.  If generation
and/or transmission  facilities are constructed,  and/or the availability of our
Ravenswood  facility  deteriorates,  then the capacity and energy sales  volumes
could be adversely affected.  We cannot predict,  however,  when or if new power
plants or transmission  facilities will be built or the nature of the future New
York City energy requirements or market design.

Regional Transmission Organizations and Standard Market Design

During 2001, the Federal Energy  Regulatory  Commission  ("FERC") issued several
orders and began  several  proceedings  related to the  development  of Regional
Transmission  Organizations  ("RTO")  and the  design  of the  wholesale  energy
markets. The details of how RTOs will be formed are currently evolving.  On July
31,  2002,  FERC issued a Notice of  Proposed  Rulemaking  ("NOPR")  intended to
establish  a  standardized  market  design and rules for  competitive  wholesale
electric markets ("Standard Market Design" or "SMD"). These rules would apply to
transmission owners ("TOs"),  independent system operators  ("ISOs"),  and RTOs.
The SMD is intended to create: (i) genuine wholesale competition; (ii) efficient
transmission  systems;  (iii)  the  right  pricing  signals  for  investment  in
transmission and generation facilities;  and (iv) more customer options. How the
SMD will be implemented  will be based on FERC's final rules in this regard,  as
well as, the subject of various compliance filings by TOs, ISOs, and RTOs. We do
not know how the markets will develop nor how these proposed changes will impact
the operations of the NYISO or its market rules.  Furthermore,  we are unable to
determine  to what  extent,  if any,  this  process  will impact the  Ravenswood
facility's financial condition, results of operations or cash flow.

New York Independent System Operator Matters

On May 31, 2002,  FERC approved the NYISO's  mitigation  plan ("the Plan").  The
Plan retains existing  mitigation measures such as $1000/MWhr energy price caps,
non-spinning  reserve bid caps, in-City capacity and energy mitigation measures,
the day ahead Automated  Mitigation  Procedure ("AMP"),  and the NYISO's general
mitigation authority.  In addition,  the Plan implements a new in-City real time
automated mitigation  procedure.  Although prices for various energy products in
the NYISO  markets have  softened,  it is not known to what extent each of these
proceedings  and revised rules may impact the  Ravenswood  facility's  financial
condition, results of operations or cash flows.

<PAGE>

Commodity Contracts and Electric Derivative Instruments

From time to time we have 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
our peak electric  energy sales.  Our hedging  objectives  and  strategies  have
remained substantially unchanged from year-end.

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 production.  As of June 30, 2002, Houston Exploration
has  hedged  approximately  64% of its  estimated  2002  yearly  production  and
approximately  40% of its estimated  2003 yearly  production.  Further,  Houston
Exploration  may enter into additional  derivative  positions for 2003 and 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 is through December 2003. The
estimated amount of gains or losses associated with such derivative  instruments
that  are  reported  in  accumulated  other  comprehensive  income  and that are
expected to be  reclassified  into  earnings over the next twelve months is $3.8
million. The measured amount of hedge ineffectiveness was immaterial.

We have also employed standard NYMEX gas futures contracts,  as well as oil swap
derivative  contracts,  to fix the purchase price for a portion of the fuel used
at the Ravenswood facility. The maximum length of time over which we have hedged
such cash flow  variability  is through  February  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 or losses associated with such derivative  instruments
that  are  reported  in  accumulated  other  comprehensive  income  and that are
expected to be  reclassified  into  earnings over the next twelve months is $1.7
million. The measured amount of hedge ineffectiveness was immaterial.

Our gas  and  electric  marketing  subsidiary,  as well as our gas  distribution
operations,  have fixed rate gas sales  contracts  and utilized  standard  NYMEX
futures  contracts to lock-in a price for future natural gas purchases.  We used
standard NYMEX futures prices to value the  outstanding  contracts.  The maximum
length of time over which we have hedged such cash flow  variability  is through
February  2003.  The estimated  amount of gains or losses  associated  with such
derivative  instruments  that are reported in  accumulated  other  comprehensive
income and that are  expected to be  reclassified  into  earnings  over the next
twelve months is $0.8 million. The measured amount of hedge  ineffectiveness was
immaterial.

We have also engaged in the use of derivative swap instruments to hedge the cash
flow  variability  associated  with a portion of our forecasted  2002 summer and
winter peak electric  energy sales from the  Ravenswood  facility.  We currently
have hedge  positions for  approximately  50% of our estimated  2002 summer peak
electric  sales  from  the  Ravenswood  facility.  We used  NYISO-location  zone
published   indices  and  standard  NYMEX  prices  to  value  these  outstanding
derivatives. The maximum length of time over which we have hedged such cash flow
variability is through  December  2002. The estimated  amount of gains or losses
associated  with such  derivative  instruments  that are reported in accumulated
other  comprehensive  income  and  that are  expected  to be  reclassified  into
earnings  over the next twelve months is $1.6  million.  The measured  amount of
hedge ineffectiveness was immaterial.

<PAGE>

KeySpan Canada has also employed electric swap contracts to lock-in the purchase
price on the  purchase  of  electricity  needed to  operate  its gas  processing
plants.  These  contracts are not exchange-  traded and we used local  published
indices 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 gains  or  losses  associated  with  such  derivative
instruments that are reported in accumulated other comprehensive income and that
are expected to be  reclassified  into earnings over the next twelve months is a
loss  of  $2.2  million.  The  measured  amount  of  hedge  ineffectiveness  was
immaterial.

The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at June 30,
2002.
<TABLE>
<CAPTION>

--------------------------- ------------ --------------- ------------ ------------- ----------------- ----------------- ------------
                               Year of       Volumes                                  Fixed Price $    Current Price $   Fair Value
          Type of Contract    Maturity        mmcf         Floor $      Ceiling $                                          ($000)
--------------------------- ------------ --------------- ------------ ------------- ----------------- ----------------- ------------

                Gas
<S>                            <C>         <C>            <C>            <C>         <C>               <C>               <C>
Collars                         2002         29,440         3.56           5.14            -            3.25 - 3.88        9,149
                                2003         25,550         3.34           4.97            -            3.72 - 4.24        1,937

Swaps -Short Natural Gas        2002          5,520           -             -             3.01          3.25 - 3.88       (2,321)
                                2003         14,600           -             -             3.19          3.72 - 4.24       (9,954)

Swaps - Long Natural Gas        2002          3,920           -             -         2.44 - 3.91       3.25 - 3.95          947
                                2003          2,110           -             -         3.10 - 4.00       3.72 - 4.04        1,017
--------------------------- ------------ --------------- ------------ ------------- ----------------- ----------------- ------------
                                             81,140                                                                          775
--------------------------- ------------ --------------- ------------ ------------- ----------------- ----------------- ------------
</TABLE>


<TABLE>
<CAPTION>
         Type of Contract      Year of Maturity       Volumes                                                          Fair Value
                                                      Barrels           Fixed Price $         Current Price $            ($000)
----------------------------- -------------------- ----------------- --------------------- ----------------------- -----------------
                Oil
----------------------------- -------------------- ----------------- --------------------- ----------------------- -----------------
<S>                                <C>                    <C>          <C>                   <C>                         <C>
Swaps - Long Fuel Oil                2002                   163,474     19.75 - 24.49         24.58 - 24.93                486
                                     2003                   346,892     20.10 - 26.72         22.19 - 23.94                405
                                     2004                     3,894     23.50 - 23.70         23.23 - 23.32                  7
----------------------------- -------------------- ----------------- --------------------- ----------------------- -----------------
                                                            514,260                                                        898
----------------------------- -------------------- ----------------- --------------------- ----------------------- -----------------
</TABLE>



<TABLE>
<CAPTION>

      Type of Contract       Year of                                          Current Price   Estimated Profit $     Fair Value
                             Maturity        MWh       Fixed Profit /Price $        $                                  ($000)
------------------------- -------------- ------------ ----------------------- --------------- ------------------- -----------------

         Electricity
<S>                           <C>           <C>           <C>                   <C>             <C>                      <C>
Tolling Arrangements           2002          732,800       26.00 - 56.50            -            4.07 - 49.07                1,635

Swaps - Long                   2002           35,328       58.70 - 60.01          26.02               -                    (1,121)
                               2003           70,080       58.70 - 60.01          28.25               -                    (2,067)
------------------------- -------------- ------------ ----------------------- --------------- ------------------- -----------------
                                             838,208                                                                       (1,553)
------------------------- -------------- ------------ ----------------------- --------------- ------------------- -----------------
</TABLE>

<PAGE>

Non-firm Gas Sales Derivative Instruments: Utility tariffs applicable to certain
large-volume  customers  permit  gas to be sold at  prices  established  monthly
within a specified range expressed as a percentage of prevailing  alternate fuel
oil prices. We used natural gas swap contracts, with offsetting positions in oil
swap contracts of equivalent energy value, to hedge the cash-flow variability of
specified  portions  of  gas  purchases  and  sales.  All  positions  that  were
outstanding  at December 31, 2001 settled  during the first  quarter of 2002. We
intend to enter into  additional  derivative  instruments  of this nature during
2002 if market conditions so warrant.

Firm Gas  Sales  Derivative  Instruments  -  Regulated  Utilities:  We have also
utilized  derivative  financial  instruments to reduce the cash flow variability
associated  with the  purchase  price for a portion  of our future  natural  gas
purchases.  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 support our gas
sales prices to regulated  firm gas sales  customers,  the  accounting for these
derivative  instruments is subject to SFAS 71. 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  during  the  appropriate  winter
heating season consistent with regulatory requirements.

The following tables set forth selected financial data associated with these
derivative financial instruments that were outstanding at June 30, 2002.
<TABLE>
<CAPTION>
----------------------------- -------------------- ------------------ ---------------------- --------------------- -----------------

         Type of Contract      Year of Maturity        Volumes                                                         Fair Value
                                                        Mmcf              Fixed Price $         Current Price $          ($000)
----------------------------- -------------------- ------------------ ---------------------- --------------------- -----------------

                Gas
<S>                                <C>                       <C>         <C>                   <C>                       <C>
Call Options                         2002                      1,280       4.20 - 4.50           3.69 - 3.95                17
                                     2003                      1,960       4.20 - 4.50           3.88 - 4.04               253
----------------------------- -------------------- ------------------ ---------------------- --------------------- -----------------
                                                               3,240                                                       270
----------------------------- -------------------- ------------------ ---------------------- --------------------- -----------------
</TABLE>

Contract Review

On April 1, 2002 we implemented Implementation Issue C15 and C16 of Statement of
Financial Accounting  Standards No. 133, "Accounting for Derivative  Instruments
and Hedging  Activities" as amended and interpreted  incorporating  SFAS 137 and
138 and certain  implementation  issues  (collectively  "SFAS  133").  Issue C15
establishes  new criteria  that must be satisfied in order for  option-type  and
forward  contracts in electricity to be exempted as normal  purchases and sales,
while Issue C16  relates to  contracts  that  combine a forward  contract  and a
purchased  option  contract.  Based  upon a  review  of our  physical  commodity
contracts,  we determined  that certain  contracts for the physical  purchase of
natural gas can no longer be exempted as normal  purchases from the requirements
of SFAS 133 as normal purchase.  As a result,  and effective April 1, 2002, such
contracts are required to be recorded on the Consolidated  Balance Sheet at fair
value and had a calculated fair value on that date of $7.8 million.  At June 30,
2002,the fair value of these  contracts was $5.0 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  will be recorded as a Regulatory  Asset or
Regulatory Liability on the Consolidated Balance Sheet.

<PAGE>

Interest  Rate  Swaps:  We also  have  interest  rate swap  agreements  in which
approximately $1.3 billion of fixed rate debt has been synthetically modified to
floating rate debt.  For the term of the  agreements,  we will receive the fixed
coupon rate  associated  with these bonds and pay the counter parties a variable
interest  rate that is reset on a quarterly  basis.  These swaps are fair- value
hedges and qualify for "short-cut"  hedge  accounting  treatment under SFAS 133.
Through  the  utilization  of our  interest  rate swap  agreements,  we  reduced
recorded  interest  expense by $22.7  million for the six months  ended June 30,
2002.  The fair values of these  derivative  instruments  are  provided to us by
third party  appraisers  and represent  the present  value of future  cash-flows
based  on a  forward  interest  rate  curve  for  the  life  of  the  derivative
instrument.

During the quarter ended June 30, 2002, the swap  arrangement  associated with a
$90 million Gas Facilities  Revenue Bond was terminated by our counter party. At
that time we had an immaterial  derivative asset recorded. As provided for under
the terms of the swap  agreement,  our counter  party had the right to terminate
the swap arrangement at their discretion without a fee or penalty. Since neither
a fee nor penalty was imposed on the counter-party, the termination of this swap
arrangement had no earnings impact.

The table  below  summarizes  selected  financial  data  associated  with  these
derivative financial instruments that were outstanding at June 30, 2002.
<TABLE>
<CAPTION>
--------------------------- ---------------------- ------------------------- -------------- ----------------------- ----------------
                                                                                               Average Variable
                              Maturity Date of         Notional Amount         Fixed Rate   Rate Paid Year to Date       Fair Value
                   Bond             Swaps                   ($000)              Received                                   ($000)
--------------------------- ---------------------- ------------------------- -------------- ----------------------- ----------------
<S>                                         <C>                  <C>            <C>                <C>                       <C>
Medium Term Notes                            2010                   500,000      7.625%             4.290%                    3,022

Medium Term Notes                            2006                   500,000      6.150%             3.320%                    4,581

Medium Term Notes                            2023                   270,000      8.200%             3.620%                    (309)
--------------------------- ---------------------- ------------------------- -------------- ----------------------- ----------------
                                                                  1,270,000                                                   7,294
--------------------------- ---------------------- ------------------------- -------------- ----------------------- ----------------
</TABLE>

Additionally,  we also have an interest rate swap agreement that hedges the cash
flow  variability  associated  with  the  forecasted  issuance  of a  series  of
commercial paper offerings. The maximum length of time over which we have hedged
such cash flow  variability is through March 2003. The estimated amount of gains
or losses  associated  with such  derivative  instruments  that are  reported in
accumulated other comprehensive  income and that are expected to be reclassified
into  earnings  over the  next  twelve  months  is a loss of $1.6  million.  The
measured amount of hedge  ineffectiveness was immaterial.  We estimate that a 1%
increase in current  interest rates would result in a $10.3 million  increase to
interest expense.

Derivative contracts are primarily used to manage our exposure to market risk
arising from changes in commodity prices and interest rates. In the event of
nonperformance by a counter party to derivative contract, the desired impact may
not be achieved. The risk of a counter party nonperformance is generally
considered credit risk and is actively managed by assessing each counter party
credit profile and negotiating appropriate levels of collateral and credit
support. Currently the majority of our derivative contracts are with investment
grade companies. (See Item 3. Quantitative and Qualitative Disclosures About
Market Risk for a discussion on credit risk.)

<PAGE>

Credit Risk

We are  exposed to credit  risk  arising  from the  potential  that our  counter
parties fail to perform on their contractual  obligations.  Our credit exposures
are created  primarily  through the sale of gas and  transportation  services to
residential,   commercial  and   industrial   customers  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 gas
production companies.

In addition to regional  concentration  of credit risk due to  receivables  from
residential, commercial and industrial customers in New York and New England, we
also have  concentrations  of credit risk from LIPA, our largest  customer,  and
from energy  companies.  Concentration  of energy  company  counter  parties may
impact  overall  exposure  to credit  risk in that our  counter  parties  may be
similarly impacted by changes in economic,  regulatory or other  considerations.
We actively  monitor the credit profile of our major counter  parties 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 limit our credit  exposure by  restricting  new
transactions with the counter party,  requiring additional  collateral or credit
support and negotiating the early termination of certain agreements.


<PAGE>

PART II.  OTHER INFORMATION

Item 1. Legal Proceedings

See Note 10 to the Financial Statements "Legal Matters"

Item 4.                 Submission of Matters to a Vote of Security Holders

We held our annual meeting of shareholders on May 9, 2002, at 10:00 a.m. Eastern
Time, at the Tilles Center for the Performing Arts, Long Island University, C.
W. Post Campus, 720 Northern Boulevard, Greenvale, New York, to consider and
take action on the following items:

1.          Election of ten directors

The names of the persons who received a plurality of the votes cast by the
holders of shares entitled to vote thereon, and who were accordingly elected
Directors of KeySpan for one year or until their successors are duly elected or
chosen and qualified are as follows:
<TABLE>
<CAPTION>
                DIRECTOR                             VOTES                       VOTES                       TOTAL
                                                      FOR                       WITHHELD                     VOTES
<S>                                             <C>                          <C>                        <C>
Robert B. Catell                                  115,384,212                  2,249,325                  117,633,537

Andrea S. Christensen                             115,387,150                  2,246,387                  117,633,537

Howard R. Curd                                    115,441,910                  2,191,627                  117,633,537

Donald H. Elliott                                 115,358,103                  2,275,434                  117,633,537

Alan H. Fishman                                   115,411,326                  2,222,211                  117,633,537

J. Atwood Ives                                    115,383,174                  2,250,363                  117,633,537

James R. Jones                                    115,400,216                  2,233,321                  117,633,537

James L. Larocca                                  115,435,440                  2,198,097                  117,633,537

Stephen W. McKessy                                114,782,537                  2,851,000                  117,633,537

Edward D. Miller                                  115,419,908                  2,213,629                  117,633,537

</TABLE>

2.   Ratification  of Deloitte & Touche LLP, as independent  public  accountants
     for the Company for the year ending December 31, 2002

Deloitte & Touche LLP received a majority of the votes cast by the holders of
shares entitled to vote thereon, and was accordingly ratified Independent Public
Accountants of KeySpan for the fiscal year ending December 31, 2002.


              DELOITTE & TOUCHE LLP                            VOTES CAST

                                FOR                           111,704,204

                            AGAINST                             4,689,073

                            ABSTAIN                             1,240,428

                              TOTAL                           117,633,705

<PAGE>


Item 6.  Exhibits and Reports on Form 8-K

(a)         Exhibits

4.1* Credit Agreement among KeySpan  Corporation,  the several Lenders, ABN AMRO
     Bank, N.V. and Citibank,  N.A., as Co-Syndication  Agents,  The Bank of New
     York and The Royal Bank of Scotland PLC, as  Co-Documentation  Agents,  and
     J.P. Morgan Chase Bank, as Administrative Agent for $1.3 billion,  dated as
     of July 9, 2002

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

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

(b)         Reports on Form 8-K

In our report on Form 8-K dated  April 5, 2002,  we  reported  that on March 29,
2002, KeySpan's Board of Directors,  upon recommendation of the Audit Committee,
determined  not to renew the  engagement of its  independent  public  accountant
Arthur Andersen LLP and appointed  Deloitte & Touche as its  independent  public
accountants.

In our report on Form 8-K dated April 25, 2002, we reported that we had issued a
press release concerning, among other things, our earnings for the quarter ended
March 31, 2002.

In our report on Form 8-K dated May 6, 2002,  we reported  that we had completed
the issuance of 8,000,000  MEDS Equity Units  initially  consisting of 8,000,000
Corporate MEDS on May 6, 2002.

In our report on Form 8-K dated July 9, 2002,  we reported  that we had issued a
press release  concerning the completion of the sale of our subsidiary,  Midland
Enterprises,  LLC ("Midland"),  a U.S. inland marine  transportation  company on
July 2, 2002.

In our report on Form 8-K dated July 25, 2002,  we reported that we had issued a
press release on July 25, 2002, concerning, among other things, its earnings for
the quarter ended June 30, 2002.

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




<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: August 12, 2002                                    /s/ Gerald Luterman
                                                  -----------------------------
                                                             Gerald Luterman
                                                  Executive Vice President and
                                                  Chief Financial Officer



Date: August 12, 2002                                /s/ Ronald S. Jendras
                                                  ------------------------------
                                                         Ronald S. Jendras
                                                  Vice President, Controller and
                                                  Chief Accounting Officer