UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549

                                    FORM 10-Q

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

                For the quarterly period ended September 30, 2002

                TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                        For the Transition period from to

                         Commission file number 1-14161

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

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

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

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

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


                      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 October 31, 2002
    ---------------------                        -------------------------------
         $.01 par value                                     142,026,375

<PAGE>

                      KEYSPAN CORPORATION AND SUBSIDIARIES

                                Table of Contents

                                                                          Page
                                                                          ----

PART I     FINANCIAL INFORMATION
           ---------------------

Item 1     Financial Statements

              Consolidated Balance Sheet:
              September 30, 2002 and December 31, 2001
                                                                           3

              Consolidated Statement of Income:
              Three and Nine  Months   Ended
              September  30,  2002 and 2001                                5

              Consolidated Statement of Cash Flows:
              Nine Months Ended September 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                             28

Item 3     Quantitative and Qualitative Disclosures
           About Market Risk                                               56


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

Item 1     Legal Proceedings                                               63

Item 4     Controls and Procedures                                         63

Item 6     Exhibits and Reports on Form 8-K                                63

           Signatures                                                      65

           Certifications                                                  66
<PAGE>


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

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

                                                                      September 30, 2002              December 31, 2001
                                                                  ---------------------------     ---------------------------

ASSETS
<S>                                                                             <C>                            <C>
Current Assets
    Cash and cash equivalents                                $                       53,925      $                 159,252
    Accounts receivable                                                           1,100,805                      1,344,898
    Allowance for uncollectible accounts                                            (67,775)                       (72,299)
    Gas in storage, at average cost                                                 327,246                        334,999
    Materials and supplies, at average cost                                         107,507                        105,693
    Other                                                                           187,050                        125,944
                                                                  ---------------------------     ---------------------------
                                                                                  1,708,758                      1,998,487
                                                                  ---------------------------     ---------------------------

Net Assets Held for Disposal                                                              -                        191,055
                                                                  ---------------------------     ---------------------------
Equity Investments and Other                                                        237,624                        223,249
                                                                  ---------------------------     ---------------------------

Property
    Gas                                                                           5,977,669                      5,704,857
    Electric                                                                      1,904,995                      1,629,768
    Other                                                                           390,526                        400,643
    Accumulated depreciation                                                     (2,671,817)                    (2,533,466)
    Gas exploration and production, at cost                                       2,378,828                      2,200,851
    Accumulated depletion                                                          (927,666)                      (796,722)
                                                                  ---------------------------     ---------------------------
                                                                                  7,052,535                      6,605,931
                                                                  ---------------------------     ---------------------------

Deferred Charges
    Regulatory assets                                                               430,284                        458,191
    Goodwill, net of amortization                                                 1,785,029                      1,782,826
    Other                                                                           667,243                        529,867
                                                                  ---------------------------     ---------------------------
                                                                                  2,882,556                      2,770,884
                                                                  ---------------------------     ---------------------------

Total Assets                                                 $                   11,881,473     $               11,789,606
                                                                  ===========================     ===========================
</TABLE>


        See accompanying Notes to the Consolidated Financial Statements.


<PAGE>



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

                                                                                 September 30, 2002              December 31, 2001
                                                                             ---------------------------     -----------------------

LIABILITIES AND CAPITALIZATION
<S>                                                                                     <C>                           <C>
Current Liabilities
    Current redemption of long-term debt                                $                    1,431             $              993
    Accounts payable and accrued expenses                                                  851,433                      1,091,430
    Commercial paper                                                                       529,228                      1,048,450
    Dividends payable                                                                       64,297                         63,442
    Taxes accrued                                                                           42,650                         50,281
    Customer deposits                                                                       36,500                         36,151
    Interest accrued                                                                       114,535                         93,962
                                                                             ---------------------------     -----------------------
                                                                                         1,640,074                      2,384,709
                                                                             ---------------------------     -----------------------



Deferred Credits and Other Liabilities
    Regulatory liabilities                                                                  68,311                         39,442
    Deferred income tax                                                                    843,956                        598,072
    Postretirement benefits and other reserves                                             715,817                        694,680
    Other                                                                                  163,268                        207,992
                                                                             ---------------------------     -----------------------
                                                                                         1,791,352                      1,540,186
                                                                             ---------------------------     -----------------------



Capitalization

    Common stock, $.01 par value, authorized
      450,000,000 shares; outstanding 141,865,724                                        2,995,666                      2,995,797
      and 137,251,386 shares stated at

    Retained earnings                                                                     439,181                         452,206
    Other comprehensive income                                                            (42,507)                          4,483
    Treasury stock purchased                                                             (494,576)                       (561,884)
                                                                             ---------------------------     -----------------------
      Total common shareholders equity                                                  2,897,764                       2,890,602
    Preferred stock                                                                        83,849                          84,077
    Long-term debt                                                                      5,260,109                       4,697,649
                                                                             ---------------------------     -----------------------
    Total Capitalization                                                                8,241,722                       7,672,328
                                                                             ---------------------------     -----------------------

Minority Interest in Subsidiary Companies                                                 208,325                         192,383
                                                                             ---------------------------     -----------------------
Total Liabilities and Capitalization                                         $         11,881,473            $         11,789,606
                                                                             ===========================     =======================
</TABLE>



         See accompanying Notes to the Consolidated Financial Statements

<PAGE>

<TABLE>
<CAPTION>
                                                   CONSOLIDATED STATEMENT OF INCOME
                                                             (Unaudited)
                                               (In Thousands, Except Per Share Amounts)

------------------------------------------------------------------------------------------------------------------------------------
                                                    Three Months          Three Months           Nine Months          Nine Months
                                                       Ended                 Ended                  Ended                Ended
                                                 September 30, 2002   September 30, 2001    September 30, 2002    September 30, 2001
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>                <C>                  <C>                     <C>
Revenues
     Gas Distribution                                  $    337,785       $    346,703        $    2,082,577          $   2,721,032
     Electric Services                                      414,868            387,881             1,084,309              1,089,156
     Energy Services                                        217,104            263,047               687,975                814,911
     Gas Exploration                                         86,464             82,362               249,452                318,093
     Energy Investments                                      23,599             22,436                62,784                 73,627
                                                 ------------------- ------------------ --------------------- ----------------------
     Total Revenues                                       1,079,820          1,102,429             4,167,097              5,016,819
                                                 ------------------- ------------------ --------------------- ----------------------

Operating Expenses
     Purchased gas for resale                               138,607            148,893             1,037,907              1,694,591
     Fuel and purchased power                               139,538            164,555               317,253                454,212
     Operations and maintenance                             485,157            507,113             1,531,394              1,544,799
     Depreciation, depletion and amortization               127,301            135,937               380,758                388,679
     Operating taxes                                         96,298             94,909               304,076                337,734
                                                 ------------------- ------------------ --------------------- ----------------------
     Total Operating Expenses                               986,901          1,051,407             3,571,388              4,420,015
                                                 ------------------- ------------------ --------------------- ----------------------
Operating Income                                             92,919             51,022               595,709                596,804
                                                 ------------------- ------------------ --------------------- ----------------------
Other Income and (Deductions)
     Minority interest                                      (5,353)            (7,694)               (15,920)               (34,970)
     Other                                                  (1,293)             6,464                 24,821                 35,286
                                                 ------------------- ------------------ --------------------- ----------------------
     Total Other Income                                     (6,646)            (1,230)                 8,901                    316
                                                 ------------------- ------------------ --------------------- ----------------------
Earnings Before Interest Charges
     and Income Taxes                                        86,273            49,792                604,610                597,120
                                                 ------------------- ------------------ --------------------- ----------------------
Interest Charges                                             79,937            78,735                222,594                263,967
                                                 ------------------- ------------------ --------------------- ----------------------
Income Taxes
     Current                                                (31,903)          (31,088)              (110,403)                53,088
     Deferred                                                33,275            39,572                243,652                103,796
                                                 ------------------- ------------------ --------------------- ----------------------
     Total Income Taxes                                       1,372             8,484                133,249                156,884
                                                 ------------------- ------------------ --------------------- ----------------------
Earnings (Loss) from Continuing Operations                    4,964           (37,427)               248,767                176,269
                                                 ------------------- ------------------ --------------------- ----------------------
Discontinued Operations
    Income from operations, net of tax                            -             2,253                 (3,356)                 6,806
    Loss on Disposal, net of tax of $13,050                       -                 -                (16,306)                     -
                                                 ------------------- ------------------ --------------------- ----------------------
Earnings (Loss) from Discontinued Operations                      -             2,253                (19,662)                 6,806
                                                 ------------------- ------------------ --------------------- ----------------------
Net Income                                                    4,964           (35,174)               229,105                183,075
Preferred stock dividend requirements                         1,335             1,473                  4,287                  4,425
                                                 ------------------- ------------------ --------------------- ----------------------
Earnings (Loss) Available for Common Stockholders       $     3,629      $    (36,647)         $     224,818           $    178,650
                                                 =================== ================== ===================== ======================
Basic Earnings (Loss) Per Share:
     Continuing Operations, less Preferred
        Stock Requirements                                     0.03             (0.28)                  1.74                   1.25
     Discontinued Operations                                   0.00              0.02                  (0.14)                  0.05
                                                 ------------------- ------------------ --------------------- ----------------------
Basic Earnings (Loss) Per Share                         $      0.03      $      (0.26)          $       1.60           $       1.30
                                                 =================== ================== ===================== ======================
Diluted Earnings (Loss) Per Share:
     Continuing Operations, less Preferred
        Stock Requirements                                     0.02             (0.28)                  1.72                   1.23
     Discontinued Operations                                   0.00              0.02                  (0.14)                  0.05
                                                 ------------------- ------------------ --------------------- ----------------------
Diluted Earnings (Loss) Per Share                       $      0.02       $     (0.26)          $       1.58            $      1.28
                                                 =================== ================== ===================== ======================
Average Shares Outstanding (000)
Basic                                                       141,686            138,693               140,929                137,856
Diluted                                                     142,359            139,508               141,760                138,921

</TABLE>
See accompanying Notes to the Consolidated Financial Statements.

<PAGE>

<TABLE>
<CAPTION>

                                                 CONSOLIDATED STATEMENT OF CASH FLOWS
                                                             (Unaudited)
                                                            (In Thousands)

------------------------------------------------------------------------------------------------------------------------------------
                                                                              Nine Months                        Nine Months
                                                                                 Ended                              Ended
                                                                           September 30, 2002                 September 30, 2001
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>                                <C>
Operating Activities
Earnings from continuing operations                                $                  248,767            $                176,269
Adjustments to reconcile earnings from continuing
operations to net cash  provided by (used in) operating
activities

    Depreciation, depletion and amortization                                           380,758                            388,679
    Deferred income tax                                                                 60,495*                           103,796
    Income from equity investments                                                      (9,713)                            (9,249)
    Dividends from equity investments                                                    1,777                              2,901
    Gain from class action settlement                                                        -                            (33,510)
    Provision for loss on contracting business                                               -                             63,682

Changes in assets and liabilities
    Accounts receivable                                                                239,569                            630,820
    Materials and supplies, fuel oil and gas in storage                                  5,939                           (110,107)
    Accounts payable and accrued expenses                                             (147,188)                          (634,596)
    Interest accrued                                                                    20,573                             85,580
    Other                                                                              (16,139)*                           13,202
                                                                     --------------------------    -------------------------------
Net Cash Provided by Operating Activities                                              784,838                            677,467
                                                                     --------------------------    -------------------------------


Investing Activities
Capital expenditures                                                                  (835,980)                          (668,494)
Proceeds from sale of assets                                                           173,935                             18,458
Other                                                                                        -                               (356)
                                                                     --------------------------    -------------------------------
Net Cash Used in Investing Activities                                                 (662,045)                          (650,392)
                                                                     --------------------------    -------------------------------


Financing Activities
Issuance of treasury stock                                                              67,308                             82,025
Issuance of long-term debt                                                             515,774                            721,474
Payment of long-term debt                                                              (99,845)                          (168,937)
Payment of commercial paper                                                           (519,222)                          (410,307)
Preferred stock dividends paid                                                          (4,287)                            (4,425)
Common stock dividends paid                                                           (187,857)                          (184,052)
Other                                                                                        9                              1,496
                                                                     --------------------------    -------------------------------
Net Cash (Used in) Provided By Financing Activities                                   (228,120)                            37,274
                                                                     --------------------------    -------------------------------
Net (Decrease) Increase  in Cash  and Cash Equivalents                                (105,327)                            64,349
Cash and Cash Equivalents at Beginning of Period                                       159,252                             83,329
                                                                     --------------------------    -------------------------------
Cash and Cash Equivalents at End of Period                           $                  53,925     $                      147,678
                                                                     ==========================    ===============================
</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").  KeySpan
operates six regulated  utilities that distribute  natural gas to  approximately
2.5 million  customers  in New York City,  Long  Island,  Massachusetts  and New
Hampshire,  making  KeySpan the fifth  largest gas  distribution  company in the
United States and the largest in the Northeast. We also own and operate electric
generating  plants in Nassau and  Suffolk  Counties on Long Island and in Queens
County in New York City.  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
September 30, 2002,  and the results of operations for the three and nine months
ended  September  30, 2002 and September 30, 2001, as well as cash flows for the
nine months ended  September 30, 2002 and September 30, 2001.  The  accompanying
financial  statements  should  be  read in  conjunction  with  the  consolidated
financial  statements and notes included in KeySpan's Annual Report on Form 10-K
for the year ended December 31, 2001, as amended, as well as KeySpan's Quarterly
Reports on Form 10-Q for the  quarters  ended June 30, 2002 and March 31,  2002.
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.

We have approximately 2.1 million common stock options  outstanding at September
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  90,770  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 and
nine months ended  September  30, 2002 and  September  30, 2001,  since to do so
would have been anti-dilutive.

<PAGE>

Under the requirements of Statement of Financial  Accounting  Standards ("SFAS")
128, "Earnings Per Share", our basic and diluted EPS are as follows:
<TABLE>
<CAPTION>
                                                                                   (In Thousands, Except Per Share)

--------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
                                                                  Three Months       Three Months       Nine Months     Nine Months
                                                                      Ended             Ended              Ended           Ended
                                                                  September 30,     September 30,      September 30,   September 30,
                                                                      2002               2001              2002              2001
--------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
<S>                                                                     <C>             <C>              <C>              <C>
Earnings (Loss) from Continuing Operations                            $  4 ,964        $  (37,427)       $ 248,767       $  176,269
   Preferred stock dividends                                             (1,335)           (1,473)          (4,287)          (4,425)
   Houston Exploration dilution (options)                                   (96)             (200)            (321)          (1,040)
--------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Earnings (Loss) from Continuing Operations
available to  common stockholders - adjusted                              3,533           (39,100)         244,159          170,804
--------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------

Weighted average shares outstanding (000)                               141,686           138,693          140,929          137,856

Add dilutive securities:

    Options                                                                 673               815              831            1,065
--------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Total weighted average shares outstanding - assuming dilution           142,359           139,508          141,760          138,921
--------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Basic Earnings (Loss) Per Share from Continuing Operations            $    0.03        $    (0.28)        $   1.74         $   1.25
--------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Diluted Earnings (Loss) Per Share from Continuing Operations          $    0.02        $    (0.28)        $   1.72         $   1.23
--------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
</TABLE>

2.  BUSINESS SEGMENTS

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

The  Gas  Distribution  segment  consists  of  six  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.

All of the energy,  capacity and ancillary  services  related to the  Ravenswood
facility is sold to the New York  Independent  System Operator  ("NYISO") energy
markets.  Further, two 79 megawatt generating  facilities located on Long Island
were  placed in service in June and July 2002.  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, plumbing, 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.

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

The  accounting  policies  of the  segments  are the same as those  used for the
preparation of the Consolidated Financial Statements. The segments are strategic
business units that are managed separately because of their different  operating
and regulatory environments. Operating results of the segments are evaluated by

<PAGE>

management on an earnings before interest and taxes ("EBIT") basis. At September
30,  2002,  the  total  assets  of each  reportable  segment  have  not  changed
materially from December 31, 2001. To reflect a complete picture of the 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,  an  inland  marine  barge
business,  this  subsidiary is reported as  discontinued  operations in 2002 and
2001.


The reportable segment information, excluding Midland, is as follows:
<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
September 30, 2002

Unaffiliated Revenue         337,785       414,868       217,104            86,464        23,599               -         1,079,820

Intersegment Revenue               -            25             -                 -           194            (219)                -

Earnings Before Interest
  and Taxes                  (38,878)      113,278        (4,455)           21,275        10,935         (15,882)           86,273

Three Months Ended
September 30, 2001

Unaffiliated Revenue         346,703       387,881       263,047            82,362        22,436               -         1,102,429

Intersegment Revenue               -            25             -                 -             -             (25)                -

Earnings Before Interest
  and Taxes                  (31,009)       96,519       (69,594)           26,787         2,418           24,671           49,792

------------------------------------------------------------------------------------------------------------------------------------
</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. Included in the three months ended September
30, 2001 is the favorable court decision  regarding the class action  settlement
recorded by our corporate holding company that increased EBIT by $22.0 million.

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 $414.9 million and $387.9 million for the three
months ended September 30, 2002 and 2001 represent  approximately 38% and 35% of
our consolidated revenues, respectively.

<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>
Nine months Ended
September 30, 2002

Unaffiliated Revenue          2,082,577      1,084,309     687,975           249,452        62,784                -        4,167,097

Intersegment Revenue                  -             75           -                 -           582             (657)               -

Earnings Before Interest
  and Taxes                     320,016        243,651     (23,901)           60,542        17,089          (12,787)         604,610

Nine months Ended
September 30, 2001

Unaffiliated Revenue          2,721,032      1,089,156     814,911           318,093        73,627                -        5,016,819

Intersegment Revenue                  -             75           -                 -             -              (75)               -

Earnings Before Interest
  and Taxes                     318,596        229,825    (133,013)          136,260        18,819           26,633          597,120

------------------------------------------------------------------------------------------------------------------------------------
</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. Included in the nine months ended September
30, 2001, is the favorable court decision  regarding the class action settlement
recorded by our corporate holding company that increased EBIT by $22.0 million.

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 $ 1.1  billion  for the nine  months  ended
September  30,  2002  and  2001  represent  approximately  26%  and  22%  of our
consolidated revenues, respectively.

<PAGE>


3.  COMPREHENSIVE INCOME

<TABLE>

The table below indicates the components of comprehensive income.
<CAPTION>
                                                                                                (In Thousands)
--------------------------------------------------------- ------------------ ----------------- ------------------ -----------------

                                                             Three Months      Three Months       Nine Months       Nine Months
                                                                Ended             Ended              Ended             Ended
                                                            September 30,     September 30,      September 30,     September 30,
                                                                2002               2001              2002               2001
--------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
<S>                                                               <C>              <C>                 <C>               <C>
Earnings (loss) available for common stockholders                 $  3,629        $  (36,647)         $  224,818        $  178,650
--------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Other comprehensive income (loss), net of tax

    Reclassification adjustment for gains
       realized in net income                                       (7,529)          (13,584)            (17,814)          (11,683)

    Foreign currency translation adjustments                        (2,313)             (179)              6,804            (8,307)

    Unrealized losses on marketable securities                      (4,027)           (2,672)             (8,263)           (5,032)

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

    Unrealized (losses) gains on derivative financial
        instruments                                                   (641)           39,004             (26,585)           54,936

--------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Other comprehensive income (loss)                                  (14,510)           22,569             (46,990)           29,914
--------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Comprehensive income (loss)                                     $  (10,881)       $  (14,078)         $  177,828        $  208,564
--------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Related tax expense (benefit)

    Reclassification adjustment for gains
       realized in net income                                       (4,054)           (7,315)             (9,592)           (6,291)

    Foreign currency translation adjustments                        (1,245)              (97)              3,663            (4,473)

    Unrealized losses on marketable securities                      (2,168)           (1,439)             (4,449)           (2,709)

    Accrued unfunded pension obligation                                  -                 -                (610)                -

    Unrealized (losses) gains on derivative financial
        instruments                                                   (346)           21,003             (14,316)           29,581
--------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Total tax expense (benefit)                                     $   (7,813)         $ 12,152         $   (25,304)        $  16,108
--------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
</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

<PAGE>

and listing with the New York Public Service Commission ("NYPSC"). The remaining
former MGP site was acquired when the  Ravenswood  facility was  purchased  from
Consolidated Edison Company of New York Inc. ("Consolidated  Edison").  Fourteen
sites are currently the subjects of Administrative Orders on Consent ("ACOs") or
Voluntary Clean-Up Agreements ("VCAs") with the DEC.


We presently estimate the remaining  environmental  cleanup costs related to our
New York MGP sites will be $146.9  million,  which  amount has been accrued as a
reasonable estimate of probable cost for known sites.  Expenditures  incurred to
date with respect to these MGP-related sites total $44.4 million.

The KEDNY and KEDLI rate plans generally provide for the recovery of MGP related
investigation  and  remediation  costs  in  rates  charged  to gas  distribution
customers.  Under  prior rate  orders,  KEDNY has  offset  certain  refunds  due
customers  against its estimated  environmental  cleanup costs for MGP sites.  A
regulatory  asset of $122.4  million for the New  York/Long  Island MGP sites is
reflected at September 30, 2002.

We are  also  responsible  for  environmental  obligations  associated  with the
Ravenswood electric generating facility.  The extent of our obligations does not
include  liabilities  arising from the  disposal of waste at off-site  locations
prior  to the  acquisition  of the  Ravenswood  facility,  or from  Consolidated
Edison's  pre-closing  conduct.  Based on  information  currently  available,  a
liability of $3.9 million has been accrued.  Expenditures  incurred to date with
respect to these environmental obligations total $1.1 million.

New England Sites. Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 75 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 65 MGP
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 $50.1 million,  which amount has been
accrued as a reasonable estimate of probable cost for known sites.  Expenditures
incurred  since  November 8, 2000 with respect to these  MGP-related  activities
total $13.3 million.

The Massachusetts  Department of  Telecommunications  and Energy ("DTE") and the
New Hampshire Public Utilities Commission ("NHPUC") have issued rate orders that
provide for the recovery of site  investigation  and remediation  costs in rates
charged to gas distribution customers.  Accordingly, a regulatory asset of $59.6
million for the KEDNE MGP sites is reflected at September 30, 2002. 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  $41.2  million,  which
amount has been  accrued as a  reasonable  estimate of probable  costs for known
sites. Expenditures incurred since November 8, 2000, with respect to these sites
total $2.0 million.  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 sites and related  facilities  identified  above are  reasonable
estimates of likely cost within a range of reasonable, foreseeable costs. We may
be required to investigate and, if necessary,  remediate each of these, or other
currently  unknown former sites and related facility sites, the cost of which is
not  presently  determinable  but may be  material  to our  financial  position,
results  of  operations  or  liquidity.  Remediation  costs for each site may be
materially higher than noted,  depending upon remediation  experience,  selected
end use for each site, and actual environmental conditions encountered.

See KeySpan's  Annual  Report on Form 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,  KeySpan had an  effective $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  the  shelf
registration  for the  issuance of an  additional  $1.2  billion of  securities,
thereby giving  KeySpan 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.

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

<PAGE>

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 the 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  KeySpan's
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  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
a  financing  amendment  with the SEC  under  PUHCA to  increase  the  financing
authority  by  $700  million,  thereby  matching  the  shelf  availability.   We
anticipate a decision by the SEC on this application by year-end.

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 ($42.36 per share) which is higher than the current per share
market value. Interest payments do, 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 basic and
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, as well as charges or credits to income.

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  Derivative  Instruments:  From  time to  time  KeySpan  has  utilized
derivative financial  instruments,  such as futures,  options and swaps, for the
purpose of hedging  exposure to commodity  price risk and to hedge the cash flow
variability  associated  with a portion of peak electric  energy sales.  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  October  31,  2002,  Houston
Exploration  has  hedged  approximately  65%  of its  estimated  2002  and  2003
production.  Further,  Houston Exploration may enter into additional  derivative

<PAGE>

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 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 $14.6 million.

KeySpan has also employed standard NYMEX gas futures  contracts,  as well as oil
swap derivative  contracts,  to hedge the cash flow  variability of a portion of
forecasted  purchases  of natural  gas and fuel oil that will be consumed at the
Ravenswood  facility.  Natural  gas  basis  swaps  are  also  utilized  to hedge
forecasted  purchases of natural gas transportation.  The maximum length of time
over which we have hedged cash flow variability  associated with: (i) forecasted
purchases of natural gas is October 2003; (ii) forecasted  purchases of fuel oil
is  through  April  2004;  and  (iii)   forecasted   purchases  of  natural  gas
transportation  is through  December 2003. We used standard NYMEX futures prices
to value the gas futures contracts and industry published oil indices for number
6 grade fuel oil to value the oil swap contracts.  The estimated amount of gains
associated with all such derivative instruments that are reported in Accumulated
Other  Comprehensive  Income  and  that are  expected  to be  reclassified  into
earnings over the next twelve months is $4.1 million.

Our retail gas and electric marketing subsidiary,  our domestic gas distribution
operations and KeSpan Canada  employed  NYMEX natural gas futures  contracts and
natural gas swaps to lock-in a price for expected  future natural gas purchases.
As applicable,  we used standard  NYMEX futures prices and relevant  natural gas
indices to value the  outstanding  contracts.  The  maximum  length of time over
which we have hedged such cash flow  variability  is through  October 2003.  The
estimated amount of gains  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 $2.5 million.

We have also engaged in the use of  cash-settled  swap  instruments to hedge the
cash flow  variability  associated  with a portion of 2002 peak electric  energy
sales from the Ravenswood  facility.  All hedge positions for the summer of 2002
have been settled. We currently have a number of remaining  derivatives that are
employed  to  hedge  cash  flow  variability  through  December  2002.  We  used
NYISO-location  zone published indices to value these  outstanding  derivatives.
The estimated amount of gains  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 $2.4 million.

KeySpan  Canada also has  employed  electricity  swap  contracts  to lock-in the
purchase price of electricity needed to operate its gas processing plants. These
contracts  are not  exchange-  traded and local  published  indices were used to
value these  outstanding swap agreements.  The maximum length of time over which
we have  hedged  such  cash flow  variability  is  through  December  2003.  The
estimated amount of losses associated with such derivative  instruments that are
reported in Accumulated Other  Comprehensive  Income and that are expected to be
reclassified into earnings over the next twelve months is $1.7 million.



<PAGE>



The following  tables set forth selected  financial data  associated  with these
derivative financial  instruments noted above that were outstanding at September
30, 2002.

<TABLE>
<CAPTION>
-------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
                                   Year of      Volumes                                  Fixed            Current        Fair Value
       Type of Contract           Maturity        mmcf        Floor $     Ceiling $      Price $           Price $          ($000)
-------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
              Gas
<S>                               <C>           <C>           <C>          <C>         <C>             <C>               <C>
Collars                             2002         14,720        3.56          5.14            -          3.69 - 4.32        (1,141)
                                    2003         32,350        3.34          4.97            -          3.90 - 4.40        (2,498)


Swaps / Futures-Short
  Natural Gas                       2002          3,191          -            -             3.01        3.69 - 4.32        (2,662)
                                    2003         15,208          -            -             3.19        3.90 - 4.40       (12,394)


Swaps / Futures - Long
  Natural Gas                       2002          2,990          -            -         2.68 - 4.24     3.90 - 4.32         1,227
                                    2003          8,210          -            -         3.10 - 4.35     3.90 - 4.40         2,359
-------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
                                                 76,669                                                                   (15,109)
-------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
       Type of Contract            Year of          Volumes                                                          Fair Value
                                  Maturity          Barrels           Fixed Price $          Current Price $           ($000)
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
             Oil
<S>                                  <C>            <C>               <C>                    <C>                       <C>
Swaps - Long Fuel Oil                 2002            146,994           19.75 - 26.40          28.65 - 29.00             1,024
                                      2003            307,822           20.10 - 26.72          23.01 - 28.96             1,613
                                      2004              5,404           20.50 - 23.70          22.84 - 23.33                 7
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
                                                      460,220                                                            2,644
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
</TABLE>

<TABLE>
<CAPTION>
-------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
      Type of Contract       Year of                                                  Current       Estimated          Fair Value
                             Maturity          MWh         Fixed Profit /Price $      Price $        Profit $            ($000)
-------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
       Electricity
<S>                           <C>          <C>                <C>                     <C>         <C>                  <C>
Tolling Arrangements           2002          102,400               26.00                 -         1.61 - 3.85           2,383

Swaps - Long                   2002           17,664           56.07 - 57.33           30.87            -                 (429)
                               2003           70,080           56.07 - 57.33           29.61            -               (1,791)

-------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
                                             190,144                                                                      163
-------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
</TABLE>

NYMEX  futures  are also used to  economically  hedge the cash flow  variability
associated  with the  purchase  of fuel for a  portion  of our  fleet  vehicles.
Further,  KeySpan  Canada has a  portfolio  of  financially-settled  natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i)  synthetically  fix the price that is paid or received by
KeySpan  Canada for  certain  physical  transactions  involving  natural gas and
natural gas liquids and (ii) transfer the price exposure of such  instruments to
other trading partners.  These derivative  financial  instruments do not qualify
for hedge accounting  under SFAS 133. At September 30, 2002,  these  instruments
had a favorable net mark-to-market value of $0.4 million,  which was recorded on
the Consolidated Balance Sheet and recorded to earnings for the quarter and nine
months ended September 30, 2002.

<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 use natural gas swap contracts, with offsetting positions in fuel
oil  swap  contracts  of  equivalent   energy  value,  to  hedge  the  cash-flow
variability  of specified  portions of gas  purchases and sales.  Currently,  no
derivative  transactions  outstanding  correspond to this particular  price risk
strategy, although we intend to enter into derivative instruments of this nature
during the fourth quarter of 2002 if market conditions warrant.

Firm  Gas  Sales  Derivative  Instruments  -  Regulated  Utilities:  We also use
derivative financial instruments to reduce the cash flow variability  associated
with the  purchase  price for a portion of 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 reduce the variability of the
purchase price of natural gas to be sold to regulated firm gas sales  customers,
the  accounting  for  these  derivative  instruments  is  subject  to  SFAS  71.
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  table sets forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at September 30, 2002.

<TABLE>
<CAPTION>
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
       Type of Contract           Year of           Volumes                                                          Fair Value
                                 Maturity            Mmcf             Fixed Price $          Current Price $           ($000)
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
             Gas
<S>                                  <C>            <C>                 <C>                        <C>                   <C>
Options                               2002             7,980             3.85 - 4.50                4.23                  1,549
                                      2003            12,960             3.85 - 4.50                4.27                  2,946

Swaps - Long                          2002               300                 4.11                   4.24                     42
                                      2003               600                 4.11                   4.21                     59
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
                                                      21,840                                                              4,596
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
</TABLE>


Other  Commodity  Derivative  Instruments:  On  April  1,  2002  we  implemented
Derivative  Implementation  Group  (DIG)  Issue  C15  and  C16 of  Statement  of
Financial  Accounting Standard 133,  "Accounting for Derivative  Instruments and
Hedging Activities", as amended and interpreted,  incorporating SFAS 137 and 138

<PAGE>

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 the exemption (as normal  purchases and normal sales)
of 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. At September 30,
2002, the fair value of these contracts was $2.0 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 have been recorded as a Regulatory  Asset or
Regulatory Liability on the Consolidated Balance Sheet.

Interest  Rate  Derivative  Instruments:  At September 30, 2002, we had interest
rate swap agreements in which  approximately $1.3 billion of fixed rate debt had
been  synthetically  modified  to  floating  rate  debt.  Under the terms of the
agreements,  we received the fixed coupon rate  associated  with these bonds and
paid the  counter-parties a variable interest rate that was reset on a quarterly
basis.  These swaps were  designated  as  fair-value  hedges and  qualified  for
"short-cut"  hedge accounting  treatment under SFAS 133. Through the utilization
of these  agreements,  we reduced recorded interest expense by $30.5 million for
the nine months ended September 30, 2002.

In early November 2002, we terminated two interest rate swap  agreements with an
aggregate  notional  amount of $1.0 billion and received  $81.0 million from our
swap  counter-parties,  of which $23.0 million represents accrued swap interest.
The  difference  between  the  termination  settlement  amount and the amount of
accrued  swap  interest,  $58.0  million,  will be  amortized to earnings (as an
adjustment to interest  expense) on a level yield basis over the remaining lives
of the  originally  hedged debt  obligations.  The remaining  swap,  which has a
notional amount of $270.0  million,  will continue to be accounted for as a fair
value hedge.

The table  below  summarizes  selected  financial  data  associated  with  these
derivative  financial  instruments  that were outstanding at September 30, 2002.
The fair values of these derivative  instruments were provided to us by our swap
counter-parties  and represent the present value of expected  future  cash-flows
associated with such transactions.

<TABLE>
<CAPTION>
-------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
                                                                                                   Average Variable
                                        Maturity Date of     Notional Amount       Fixed Rate          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%           4.250%              55,077

Medium Term Notes                             2006               500,000               6.150%           3.590%              37,145

Long Term Notes                               2023               270,000               8.200%           3.770%               6,843
-------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
                                                               1,270,000                                                    99,065
-------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
</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.

Weather  Derivatives:  The utility  tariffs  associated with the New England gas
distribution operations do not contain a weather normalization  adjustment. As a
result,  fluctuations  from normal  weather may have a  significant  positive or
negative  effect on the results of these  operations.  To mitigate the effect of
fluctuations  from normal weather on our financial  position and cash flows,  we
entered into weather collars during the quarter ended September 30, 2002.  These
derivatives will hedge  approximately  60% of expected gas throughput of the New
England gas distribution  companies during the November 2002 - March 2003 winter
season. The collars have been established with a ceiling that reflects 1% colder
than  normal  weather and a floor that  reflects 7% warmer than normal  weather.
KeySpan  will be required  to make  payment to its  counter-parties  when actual
weather  experienced  during the November  2002 - March 2003 time frame is 1% or
more colder than normal,  based on the 1975 - 1995 20 year average. In the event
that actual weather is 7% or more warmer than normal the counter-parties will be
required to make payment to KeySpan.  These derivatives will be accounted for by
applying the "intrinsic value method" and are outside the scope of SFAS 133.

Derivative  contracts  are  primarily  used to manage  exposure  to market  risk
arising  from changes in commodity  prices and interest  rates.  In the event of
nonperformance by a counter-party to a 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  KeySpan's  derivative  contracts  are with
investment grade companies.

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 September 30, 2002, we had paid $11.9
million for these programs and had a remaining liability of $6.7 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

<PAGE>

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 was 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.  During the
second quarter of 2002, we completed our analysis for all of the reporting units
and determined  that no  consolidated  impairment  exists.  Consistent  with the
requirements  of SFAS 142, we will annually test our goodwill for  impairment in
the fourth  quarter,  absent the  occurrence of any event that would cause us to
perform a test in the interim.

For the three and nine months ended  September 30, 2001  respectively,  goodwill
amortization was recorded in each segment as follows:  Gas Distribution $8.9 and
$26.6 million; Energy Services $1.8 and $5.8 million; and Energy Investments and
other $1.4 and $4.5 million.  As required by SFAS 142, below is a reconciliation
of reported  earnings  available for common  stockholders for the three and nine
months ended  September 30, 2001 and pro-forma net income,  for the same period,
adjusted for the discontinuance of goodwill amortization.

<TABLE>
<CAPTION>
                                                                                                  (In Thousands)
------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
                                                          Three Months      Three Months       Nine Months        Nine Months
                                                             Ended              Ended             Ended              Ended
                                                         September 30,      September 30,     September 30,      September 30,
                                                              2002              2001               2002              2001
------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
<S>                                                              <C>              <C>               <C>                <C>
Earnings (loss) available for common stockholders             $    3,629        $  (36,647)        $  224,818         $  178,650
   Add back: goodwill amortization                                     -            12,015                  -             36,879
------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Adjusted net income                                                3,629           (24,632)           224,818            215,529
------------------------------------------------------- ----------------- ------------------ ----------------- ------------------

Basic earnings (loss) per share                                     0.03             (0.26)              1.60               1.30
   Add back: goodwill amortization                                     -              0.09                  -               0.27
------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Adjusted basic earnings per share                              $    0.03        $    (0.17)         $    1.60          $    1.57
------------------------------------------------------- ----------------- ------------------ ----------------- ------------------

Diluted earnings (loss) per share                                   0.02             (0.26)              1.58               1.28
Add back: goodwill amortization                                        -              0.09                  -               0.27
------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Adjusted diluted earnings per share                            $    0.02        $    (0.17)         $    1.58          $    1.55
------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
</TABLE>


In July of 2001,  the FASB issued  SFAS 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.


<PAGE>


SFAS 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 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
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 September 30, 2002, implementation of this Statement did not
have a significant effect on our results of operations and financial position.

In June of 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with
Exit or Disposal Activities".  This Statement addresses financial accounting and
reporting for costs  associated  with exit or disposal  activities and nullifies
Emerging  Issues Task Force Issue No.94-3,  "Liability  recognition  for Certain
Employee  Termination  benefits  and  Other  Costs  to Exit an  Activity".  This
Statement is effective for exit or disposal activities  initiated after December
31, 2002 with early application encouraged.

9.  DISCONTINUED OPERATIONS

On November 8, 2000,  KeySpan acquired Midland  Enterprises LLC ("Midland"),  an
inland marine transportation subsidiary, as part of the Eastern acquisition.  In
its order issued under PUHCA approving the acquisition, the SEC required KeySpan
to sell this  subsidiary  by November 8, 2003  because its  operations  were not
functionally related to KeySpan's core utility operations.  On July 2, 2002, the
sale of Midland to Ingram  Industries  Inc.  was  completed  and net proceeds of
$173.9 million were received from the sale.

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 the tax structuring  strategy  related to the sale of Midland,  in the second
quarter of 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.


<PAGE>


The following is selected  financial  information  for Midland for the three and
nine months ended September 30, 2002 and September 30, 2001:

<TABLE>
<CAPTION>
                                                                                                       (In Thousands)
--------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
                                                    Three Months         Three Months          Nine Months          Nine Months
                                                       Ended                 Ended                Ended                Ended
                                                   September 30,         September 30,        September 30,        September 30,
                                                        2002                 2001                  2002                 2001
--------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
<S>                                                     <C>               <C>                 <C>                   <C>
Revenues                                      $          -          $       67,342       $      116,149       $       202,705
Pretax income (loss)                                     -                   3,868               (4,624)               11,727
Income tax (expense) benefit                             -                  (1,615)               1,268                (4,921)
--------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
Income (loss) from discontinued operations               -                   2,253               (3,356)                6,806
--------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
Loss on disposal                                         -                       -              (16,306)                    -
--------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
Loss from discontinued operations             $          -          $        2,253       $      (19,662)      $         6,806
--------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
</TABLE>


Assets and liabilities of the discontinued operations are as follows:
<TABLE>
<CAPTION>
                                                                                                      (In Thousands)
                 -------------------------------------------- -- ------------------------ --- -----------------------
                                                                   September 30, 2002            December 31, 2001
                 ----------------------------------------------------------------------------------------------------
                <S>                                                       <C>                     <C>
                 Current assets                               $             -             $          139,522
                 Property, plant and equipment, net                         -                        316,626
                 Long-term assets                                           -                         35,233
                 Current liabilities                                        -                        (58,835)
                 Long-term liabilities                                      -                       (241,491)
                 -------------------------------------------- -- ------------------------ --- -----------------------
                 Net assets held for disposal                 $             -             $          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.

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.

<PAGE>

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. On November 1, 2002,
we filed a motion  to  dismiss  the  class  action  lawsuits.  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. At
the  present  time,  KeySpan  is  unable  to  determine  the  outcome  of  these
proceedings,  but does not believe that such  outcome,  if adverse,  will have a
material effect on its financial condition or results of operation.

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.

KeySpan  subsidiaries,  along with  several  other  parties,  have been named as
defendants in numerous  proceedings filed by plaintiffs claiming various degrees
of injury from asbestos exposure.  Most of these proceedings have been commenced
in the New York State Supreme Court for New York County by contractor  employees
allegedly  as  a  result  of  exposure  to  asbestos  in  connection   with  the
construction  and  maintenance  of our electric  generating  facilities.  At the
present time,  KeySpan is unable to determine the outcome of these  proceedings,
but does not believe that such outcome, if adverse,  will have a material effect
on its financial condition or results of operation.

<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)
---------------------------------------------------------------------------------- -------------------------------------------------
                                   Three Months Ended September 30, 2002                  Three Months Ended September 30, 2001
------------------------------------------------------------------------------------------------------------------------------------
                             Guarantor      KEDLI    Eliminations Consolidated     Guarantor      KEDLI   Eliminations  Consolidated
<S>                        <C>             <C>          <C>        <C>            <C>           <C>           <C>        <C>
Revenues                  $  1,000,103 $    79,717  $          -  $  1,079,820  $  1,019,848  $   82,581  $        -    $ 1,102,429
Operating Expenses
Purchased Gas                  102,658      35,949             -       138,607       117,511      31,382           -        148,893
Fuel and purchased power       139,538           -             -       139,538       164,555           -           -        164,555
Operations and maintenance     472,710      12,447             -       485,157       498,528       8,585           -        507,113
Intercompany expense           (19,007)     19,007             -             -       (18,998)     18,998           -              -
Depreciation and
  amortization                 115,351      11,950             -       127,301       125,504      10,433           -        135,937
Operating Taxes                 78,764      17,534             -        96,298        76,556      18,353           -         94,909
                          ------------ ------------ ------------- ------------- ------------- ----------- ------------- ------------
Total Operating Expenses       890,014      96,887             -       986,901       963,656      87,751           -      1,051,407
                          ------------ ------------ ------------- ------------- ------------- ----------- ------------- ------------
Operating Income               110,089     (17,170)            -        92,919        56,192      (5,170)          -         51,022
Other Income and
  (Deductions)                  (3,373)      1,769        (5,042)       (6,646)           10       3,400      (4,640)        (1,230)
                          ------------ ------------ ------------- ------------- ------------- ----------- ------------- ------------
Income Before Interest
  Charges and Income Taxes     106,716     (15,401)       (5,042)       86,273        56,202      (1,770)     (4,640)        49,792
Interest Expense                69,906      15,073        (5,042)       79,937        68,704      14,671      (4,640)        78,735
Income Taxes                    12,945     (11,573)            -         1,372        14,938      (6,454)          -          8,484
                          ------------ ------------ ------------- ------------- ------------- ----------- ------------- ------------
Earnings (Loss) From
  Continuing Operations   $     23,865 $   (18,901)  $         -  $      4,964  $    (27,440) $   (9,987) $       -     $   (37,427)
                          ============ ============ ============= ============= ============= =========== ============= ============
</TABLE>

<TABLE>
<CAPTION>

Statement of Income
                                                                                      (In Thousands)
------------------------------------------------------------------------------------------------------------------------------------
                                           Nine months Ended September 30, 2002              Nine months Ended September 30, 2001
------------------------------------------------------------------------------------------------------------------------------------
                             Guarantor     KEDLI   Eliminations   Consolidated    Guarantor      KEDLI    Eliminations  Consolidated
<S>                        <C>           <C>               <C>     <C>          <C>             <C>           <C>       <C>
Revenues                  $ 3,630,496  $  536,601  $         -  $   4,167,097 $   4,365,604  $    651,215   $       -    $5,016,819
Operating Expenses
Purchased Gas                 796,518     241,389            -      1,037,907     1,330,410       364,181           -     1,694,591
Fuel and purchased power      317,253           -            -        317,253       454,212             -           -       454,212
Operations and maintenance  1,493,880      37,514            -      1,531,394     1,504,442        40,357           -     1,544,799
Intercompany expense          (57,250)     57,250            -              -       (64,198)       64,198           -             -
Depreciation and
  amortization                333,228      47,530            -        380,758       364,177        24,502           -       388,679
Operating Taxes               241,848      62,228            -        304,076       269,775        67,959           -       337,734
                          ------------ ----------- ------------ -------------- ------------- ------------- ------------- -----------
Total Operating Expenses    3,125,477     445,911            -      3,571,388     3,858,818       561,197           -     4,420,015
                          ------------ ----------- ------------ -------------- ------------- ------------- ------------- -----------
Operating Income              505,019      90,690            -        595,709       506,786        90,018           -       596,804
Other Income and
  (Deductions)                 18,122       6,860      (16,081)         8,901         5,711         9,979     (15,374)          316
                          ------------ ----------- ------------ -------------- ------------- ------------- ------------- -----------
Income Before Interest
  Charges and Income Taxes    523,141      97,550      (16,081)       604,610       512,497        99,997     (15,374)      597,120

Interest Expense              192,500      46,175      (16,081)       222,594       234,233        45,108     (15,374)      263,967
Income Taxes                  110,466      22,783            -        133,249       139,094        17,790           -       156,884

                          ------------ ----------- ------------ -------------- ------------- ------------- ------------- -----------
Earnings (Loss) from
  Continuing Operations    $  220,175  $   28,592  $         -   $    248,767   $   139,170  $     37,099   $       -    $  176,269
                          ============ =========== ============ ============== ============= ============= ============= ===========
</TABLE>

<PAGE>


<TABLE>
<CAPTION>
Balance Sheet                                                                                                    (In Thousands)
------------------------------------------------------------------------------------------------------------------------------------
                                          September 30, 2002                                   December 31, 2001
------------------------------------------------------------------------------------------------------------------------------------
ASSETS                        Guarantor     KEDLI     Eliminations  Consolidated   Guarantor    KEDLI     Eliminations  Consolidated

Current Assets
<S>                          <C>            <C>        <C>         <C>           <C>           <C>          <C>           <C>
  Cash and temporary cash
    investments            $      53,925  $        -   $       -   $    53,925    $  159,252  $        -   $        -    $  159,252
  Accounts Receivable, net     1,198,151     131,409    (296,530)    1,033,030     1,540,082     233,013     (500,496)    1,272,599
  Other current assets           495,270     126,533           -       621,803       454,319     112,317            -       566,636
                           ---------------------------------------------------    --------------------------------------------------
                               1,747,346     257,942    (296,530)    1,708,758     2,153,653     345,330     (500,496)    1,998,487
                           ---------------------------------------------------    --------------------------------------------------
Assets Held for Disposal               -           -           -             -       191,055           -            -       191,055
Equity Investments               770,486           -    (532,862)      237,624       756,111           -     (532,862)      223,249
                           ---------------------------------------------------    --------------------------------------------------
Property
  Gas                          4,250,404   1,727,265           -     5,977,669     4,074,894   1,629,963            -     5,704,857
  Other                        4,674,349           -           -     4,674,349     4,231,262           -            -     4,231,262
  Accumulated depreciation
   and depletion              (3,285,338)   (314,145)          -    (3,599,483)   (3,035,788)   (294,400)           -    (3,330,188)
                           ---------------------------------------------------    --------------------------------------------------
                               5,639,415   1,413,120           -     7,052,535     5,270,368   1,335,563            -     6,605,931
                           ---------------------------------------------------    --------------------------------------------------

Deferred Charges               2,693,952     188,604           -     2,882,556     2,571,029     199,855            -     2,770,884
                           ---------------------------------------------------    --------------------------------------------------

Total Assets               $  10,851,199  $1,859,666  $ (829,392)  $11,881,473   $10,942,216  $1,880,748  $(1,033,358)  $11,789,606
                           ===================================================    ==================================================


LIABILITIES
AND CAPITALIZATION


Current Liabilities
  Accounts Payable
    and accrued expenses   $     805,704    $  45,729 $          -   $  851,433      975,873  $   115,557  $        -   $ 1,091,430
  Commercial Paper               529,228            -            -      529,228    1,048,450            -           -     1,048,450
  Other current
   liabilities                   182,690       76,723            -      259,413      220,985       23,844           -       244,829
                               -------------------------------------------------- --------------------------------------------------
                               1,517,622      122,452            -    1,640,074    2,245,308      139,401           -     2,384,709
                               -------------------------------------------------- --------------------------------------------------
Intercompany
  Accounts Payable                     -      120,626     (120,626)           -            -      324,592    (324,592)            -
                               -------------------------------------------------- --------------------------------------------------

Deferred Credits
   and Other Liabilities

  Deferred Income Tax            664,859      179,097            -      843,956      593,300       4,772            -       598,072

  Other deferred credits
     and liabilities             850,028       97,368            -      947,396      841,662     100,452            -       942,114
                               -------------------------------------------------- --------------------------------------------------
                               1,514,887      276,465            -    1,791,352    1,434,962     105,224            -     1,540,186
                               -------------------------------------------------- --------------------------------------------------

Capitalization
  Common shareholders'
        equity                 2,791,407     639,219      (532,862)   2,897,764     2,812,837     610,627    (532,862)    2,890,602
  Preferred stock                 83,849           -             -       83,849       84,077            -           -        84,077
  Long-term debt               4,735,109     700,904      (175,904)   5,260,109     4,172,649     700,904    (175,904)    4,697,649
                               -------------------------------------------------- --------------------------------------------------
Total Capitalization           7,610,365   1,340,123      (708,766)   8,241,722     7,069,563   1,311,531    (708,766)    7,672,328
                               -------------------------------------------------- --------------------------------------------------

Minority Interest
  in Subsidiary Companies        208,325           -             -      208,325       192,383           -           -       192,383
                               -------------------------------------------------- --------------------------------------------------
Total Liabilities
  and Capitalization         $10,851,199  $1,859,666  $   (829,392)  $11,881,473  $10,942,216  $1,880,748 $(1,033,358) $ 11,789,606
                               ================================================== ==================================================
</TABLE>


<PAGE>

<TABLE>
<CAPTION>

Statement of Cash Flows                                                                                         (In Thousands)
------------------------------------------------------------------------------------ -----------------------------------------------
                                       Nine Months Ended September 30, 2002             Nine Months Ended September 30, 2001
------------------------------------------------------------------------------------ -----------------------------------------------
                                    Guarantor         KEDLI          Consolidated         Guarantor        KEDLI        Consolidated
----------------------------------------------- ----------------- ------------------ ---------------- ---------------- -------------
Operating Activities
<S>                                <C>              <C>                <C>             <C>              <C>              <C>
Net Cash Provided by
   Operating Activities        $     492,665    $      292,173    $      784,838     $     614,227    $    63,240     $     677,467
                               ---------------- ----------------- ------------------ ---------------- ---------------- -------------
Investing Activities

Capital expenditures                (734,136)         (101,844)         (835,980)         (590,104)       (78,390)         (668,494)
Sale of Assets                       173,935                 -           173,935            18,458              -            18,458
Other                                      -                 -                 -              (356)             -              (356)
                               ---------------- ----------------- ------------------ ---------------- ---------------- -------------
Net Cash Used in
   Investing Activities            (560,201)          (101,844)         (662,045)         (572,002)       (78,390)         (650,392)
                               ---------------- ----------------- ------------------ ---------------- ---------------- -------------
Financing Activities

Issuance of Treasury Stock           67,308                  -            67,308            82,025              -            82,025
Issuance of long-term debt          515,774                  -           515,774           596,474        125,000           721,474
Payment of long-term debt           (99,845)                 -           (99,845)         (168,937)             -          (168,937)
Payment of commercial paper        (519,222)                 -          (519,222)         (410,307)             -          (410,307)
Preferred stock dividends paid       (4,287)                 -            (4,287)           (4,425)             -            (4,425)
Common stock dividends paid        (187,857)                 -          (187,857)         (184,052)             -          (184,052)
Net intercompany accounts
  payable                           190,329           (190,329)                -           109,850       (109,850)                -
Other                                     9                  -                 9             1,496              -             1,496
                               ---------------- ----------------- ------------------ ---------------- ---------------- -------------

Net Cash Provided by
   (Used in) Financing
     Activities                 $   (37,791)    $     (190,329)   $     (228,120)     $     22,124    $    15,150      $     37,274
                               ---------------- ----------------- ------------------ ---------------- ---------------- -------------
Net Increase in Cash and
   Cash Equivalents             $  (105,327)    $            -    $     (105,327)     $     64,349    $         -      $     64,349
                               ================ ================= ================== ================ ================ =============
Cash and Cash Equivalents at
   Beginning of Period          $   159,252     $            -    $      159,252      $     83,329    $         -      $     83,329
                               ---------------- ----------------- ------------------ ---------------- ---------------- -------------
Cash and Cash Equivalents at
   End of Period                $    53,925     $            -    $       53,925      $    147,678    $         -      $    147,678
                               ================ ================= ================== ================ ================ =============

</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
nine months  ended  September  30,  2002,  compared to the three and nine months
ended September 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 months ended
September 30, 2002 were $5.0 million compared to a loss of $37.4 million for the
same period last year.  Consolidated earnings from continuing operations for the
nine months  ended  September  30, 2002 were $248.8  million  compared to $176.3
million for the corresponding  period last year.  Earnings  available for common
stock,  which  includes  preferred  stock  dividends,  as well  as  discontinued
operations as discussed  below,  were $3.6  million,  or $0.03 per share for the
three months ended  September 30, 2002 compared to a loss of $36.6  million,  or
$0.26 per share for the same quarter last year.  Earnings  available  for common
stock for the nine months ended September 30, 2002 were $224.8 million, or $1.60
per share  compared  to $178.7  million,  or $1.30 per share for the same period
last  year.  Diluted  earnings  per share were $0.02 and $1.58 for the three and
nine months ended September 30, 2002,  respectively.  Diluted earnings per share
were $1.28 for the nine  months  ended  September  30,  2001.  Basic and diluted
earnings per share were the same for the three months ended September 30, 2001.

Average common shares  outstanding  for the nine months ended September 30, 2002
increased  by  2.2%  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 nine months  ended  September  30, 2002,  by
$0.03 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"),  KeySpan's inland marine barge business. In
anticipation  of this  divestiture,  which  closed  on July 2,  2002,  Midland's
operations have been reported as discontinued  for 2002 and 2001. (See KeySpan's
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, 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 was  recorded.  During  the  second  quarter of
2002, an  additional  after-tax  loss of $19.7  million was recorded,  primarily
reflecting  a provision  for certain city and state taxes that  resulted  from a
change in the tax structuring strategy for this transaction.  (See Note 9 to the
Consolidated   Financial  Statements   "Discontinued   Operations"  for  further
disclosures on the sale of Midland.)

<PAGE>

As discussed in more detail below,  results from  operations for the quarter and
nine months ended  September  30, 2002 compared to the  comparable  periods last
year were principally  impacted by the following factors: (i) losses incurred in
2001 by one of our  unregulated  subsidiaries;  (ii) a reversal,  in 2001,  of a
previously recorded loss provision relating to a class action settlement;  (iii)
the  discontinuation  of  goodwill  amortization  in  2002;  (iv) a  significant
decrease  in interest  expense;  and (v) a  significant  decrease in natural gas
prices,  which reduced comparative  earnings associated with gas exploration and
production operations.

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 nine  months  ended  September  30, 2001 were $56.6
million after-tax,  or $0.41 per share and $92.2 million after-tax, or $0.67 per
share, respectively. (See KeySpan's 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 11 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 nine  months  ended  September  30,  2002,  we  incurred
after-tax  losses of $3.6  million and $6.4  million,  respectively,  reflecting
increases in the estimates of and costs to complete these  contracts and general
and administrative expenses.

Included in results of operations for the three and nine months ended  September
30, 2001,  is the reversal of a previously  recorded  loss  provision  regarding
certain rate refund  issues  relating to the 1989 RICO class action  settlement.
This  adjustment was due to the favorable  United States Court of Appeals ruling
received in September  2001 and resulted in a positive  after-tax  adjustment to
earnings  of $20.1  million,  or $0.15 per  share.  This  adjustment,  which was
recorded at our holding  company  level,  has been  reflected as a $22.0 million
reduction to Operations and Maintenance expense and a reduction of $11.5 million
to Interest expense on the September 30, 2001 Consolidated  Statement of Income.
(See  KeySpan's  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 12 to those  Consolidated  Financial  Statements  "Class
Action Settlement" for a more detailed discussion.)

In January 2002, we adopted Statement of Financial  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 nine months ended  September 30, 2001 was $12.0 million,  or $0.09 per
share, and $36.9 million, or $0.27 per share, respectively.

Interest expense,  excluding the $11.5 million adjustment  recorded in September
2001 for the RICO class action  settlement  previously  mentioned,  decreased by
$10.3  million ($6.7  million  after-tax),  or $0.05 per share and $52.9 million

<PAGE>

($34.4  million  after-tax)  or $0.24 per share,  for the three and nine  months
ended September 30, 2002,  respectively.  The weighted  average interest rate on
outstanding commercial paper during the nine months ended September 30, 2002 was
approximately 2.05% compared to approximately 5.20% for the corresponding period
last year. Further,  KeySpan had a number of interest rate swap agreements which
effectively  converted  fixed rate debt to floating rate debt.  The use of these
derivative instruments reduced interest expense by $30.5 million during the nine
months ended  September  30,  2002.  (See Note 6 to the  Consolidated  Financial
Statements  "Derivative  Financial  Instruments"  for  a  description  of  these
instruments.)

For the three and nine months  ended  September  30,  2002,  net income from gas
exploration and production  operations  decreased by $4.2 million,  or $0.03 per
share and by $43.1  million,  or $0.32 per share,  respectively  compared to the
corresponding periods last year. The gas exploration and production subsidiaries
were adversely  impacted by  significantly  lower realized gas prices during the
nine months ended September 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 $11.9 million
recognized  during the nine months ended September 30, 2002,  resulting from the
favorable  resolution of certain outstanding tax issues related to the KeySpan /
Long Island Lighting  Company  ("LILCO")  merger  completed in May 1998. For the
three and nine months ended September 30, 2002, income tax expense also reflects
the beneficial effect of a change in federal income tax regulation. Beginning in
2002, certain costs associated with employee deferred compensation plans are now
tax-deductible for federal income tax purposes. These costs, however, can not be
expensed for "book" purposes,  resulting in a permanent book-to-tax  difference.
Further,  during the first quarter of 2002,  an  adjustment  to deferred  income
taxes of $177.7  million was  recorded to reflect a decrease in the tax basis of
the assets  acquired at the time of the KeySpan / LILCO merger.  This adjustment
resulted from a revised  valuation  study and the  preparation of an amended tax
return.  Concurrent  with the deferred tax  adjustment,  KeySpan reduced current
income taxes payable by $183.2  million,  resulting in a net $5.5 million income
tax benefit.  In addition,  goodwill  amortization  recorded in 2001 was not tax
deductible, also impacting comparative income tax expense.

Earnings before interest and taxes ("EBIT")  increased by $36.5 million and $7.5
million for the three and nine months ended  September  30,  2002,  respectively
compared to the corresponding  periods last year.  Comparative EBIT results were
impacted by the items mentioned  above,  namely (i) EBIT losses of $72.6 million
and $133.7  million  incurred  by the Roy Kay  companies  for the three and nine
months ended September 30, 2001, respectively; (ii) the reversal of a previously
recorded loss provision  relating to a class action settlement of $22.0 million;
(iii) the discontinuation of goodwill  amortization in 2002 of $12.0 million and
$36.9  million  for  the  three  and  nine  months  ended  September  30,  2001,
respectively; and (iv) decreases in comparative EBIT results associated with gas
exploration  and production  subsidiaries  of $5.5 million and $75.7 million for
the three and nine months ended September 30, 2002, respectively.  The remaining
decrease  in EBIT from core  operations  for the  three  and nine  months  ended
September 30, 2002 compared to last year, primarily reflects lower EBIT from the
Gas  Distribution  and  Energy  Services  segments.  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.

<PAGE>

We are  reaffirming  our  earnings  guidance of $2.60 to $2.75 per share,  which
includes  earnings from continuing core operations  (defined for this purpose as
all  continuing  operations  other than gas  exploration  and  production,  less
preferred  stock  dividends)  of  approximately  $2.40 to $2.45  per  share  and
earnings from gas exploration and production operations of approximately $0.20 -
$0.30 per share. 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. It should be noted
that,  starting in 2003,  KeySpan will begin  expensing stock options granted to
its  employees  in  order  to  reflect  all  prospective  compensation  costs in
earnings. Based on current estimates, expensing stock options is not expected to
have a significant impact on results of operations in 2003.

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 annual 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 net 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 )
   ------------------------------------------- ------------------- -------------------- ------------------- --------------------
                                                  Three Months         Three Months          Nine Months            Nine Months
                                                     Ended                Ended                 Ended                  Ended
                                                  September 30,       September 30,          September 30,         September 30,
                                                      2002                2001                    2002                  2001
   ------------------------------------------- ------------------- -------------------- ------------------- --------------------
  <S>                                                   <C>                  <C>               <C>                  <C>
   Revenues                                             $ 337,785           $  346,703         $ 2,082,577          $ 2,721,032
   Purchased gas for resale                               130,698              144,279             980,638            1,578,074
   Revenue taxes                                           10,597               12,199              67,055               89,841
   ------------------------------------------- ------------------- -------------------- ------------------- --------------------
   Net Revenues                                           196,490              190,225           1,034,884            1,053,117
   ------------------------------------------- ------------------- -------------------- ------------------- --------------------
   Operating expenses
     Operations and maintenance                           147,023              125,276             445,330              442,504
     Depreciation and amortization                         56,174               60,341             177,312              191,677
     Operating taxes                                       35,375               38,331             103,023              112,469
   ------------------------------------------- ------------------- -------------------- ------------------- --------------------
   Total Operating Expenses                               238,572              223,948             725,665              746,650
   ------------------------------------------- ------------------- -------------------- ------------------- --------------------
   Operating Income                                       (42,082)             (33,723)            309,219              306,467
   Other Income and (Deductions)                            3,204                2,714              10,797               12,129
   ------------------------------------------- ------------------- -------------------- ------------------- --------------------
   Earnings Before Interest and Taxes                  $  (38,878)           $ (31,009)          $ 320,016           $  318,596
   ------------------------------------------- ------------------- -------------------- ------------------- --------------------
   Firm gas sales (MDTH)                                   23,132               23,095             171,797              186,427
   Firm transportation (MDTH)                              22,429               20,330              65,924               76,818
   Transportation - Electric
         Generation   (MDTH)                               27,709               29,341              54,250               45,473
   Other sales (MDTH)                                      32,157               26,356              93,571               75,190
   Warmer than normal -  New York                             N/A                  N/A               15.0%                 2.0%
   Warmer (Colder) than normal - New  England                 N/A                  N/A               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 sold and  associated  revenue
taxes)  associated with both the 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 nine months
ended  September 30, 2002 was  approximately  10% - 15% warmer than normal,  and
approximately  14% warmer than last year in the New York and New England service
territories. The significantly warmer than normal weather resulted in a decrease
of $18.2 million, or 2%, in net gas revenues for the nine months ended September
30, 2002, compared to the corresponding period last year.

KEDNY and KEDLI  each  operate  under  utility  tariffs  that  contain 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  in 2002.  Nevertheless,  net
revenues  from  firm  gas  customers  (residential,  commercial  and  industrial
customers) in our New York service territory  decreased by $16.9 million for the
nine months ended  September 30, 2002 compared to the same period last year. The
decrease in net revenues  resulted from declining  usage per customer due to the
extremely  warm  weather and the use of more  efficient  gas  heating  equipment
offset,  in part,  by the  benefits  from  conversions  to natural  gas and $7.9
million of rate incentives and recoveries.

Net  revenues  from firm gas  customers  in the New  England  service  territory
decreased by $1.8 million for the nine months ended September 30, 2002, compared
to the same period last year,  also due to the extremely  warm weather.  The New
England based gas distribution  subsidiaries do not have a weather normalization
adjustment.  Included in net revenues for the nine months  ended  September  30,
2002 are base rate adjustments  totaling $8.9 million associated with Boston Gas
Company's  Performance  Based Rate Plan ("PBR").  The largest  component of this
adjustment  reflects  the  beneficial  effect  of  a  favorable  ruling  of  the
Massachusetts    Supreme   Judicial   Court   relating   to   the   "accumulated
inefficiencies" component of the productivity factor in the PBR. The court found
that the "accumulated  inefficiencies"  component  imposed by the  Massachusetts
Department of  Telecommunications  and Energy, was not supportable.  This ruling
resulted in a benefit to comparative net margins of $5.6 million. (See KeySpan's
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 2002,  excluding  gas  cost  recoveries,  have
remained  substantially   unchanged  from  last  year  in  all  of  our  service
territories.  To mitigate,  to some extent, the effect of fluctuations in normal
weather  patterns  on  KEDNE's  financial  position  and  cash  flows,   weather
derivatives are in place for the 2002/2003 winter heating season.  See Note 6 to
the Consolidated  Financial  Statement  "Derivative  Financial  Instruments" for
further information.

In our large-volume  heating and other interruptible  (non-firm) markets,  which
include large apartment houses, government buildings and schools, gas service is
provided under rates that are  established to compete with prices of alternative
fuel,  including  No. 2 and No. 6 grade  heating oil. Net margins  realized from
these  customers for the nine months ended  September 30, 2002 are comparable to
such margins  realized last year.  The majority of these margins earned by KEDNE
and KEDLI 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 the 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 the 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 the
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 10% during the nine
months ended September 30, 2002,  compared to the same period in 2001 due to the
extremely  warm  weather  and  declining  usage per  customer 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 KeySpan's  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 had a portfolio  management  contract with
El Paso Energy Marketing,  Inc. ("El Paso"), under which El Paso provided all of
the city gate supply  requirements at market prices and managed certain upstream
capacity, underground storage and term supply contracts for KEDNE. Our agreement
with El Paso expired on October 31, 2002 and our agreement with Coral expires on
March 31, 2003. We have negotiated a new agreement with  Entergy-Koch to replace
the expired El Paso  agreement.  The new agreement with  Entergy-Koch  begins on
November 1, 2002 and extends through March 31, 2003.

Purchased Gas for Resale

The decrease in gas costs for the nine months ended September 30, 2002 of $597.4
million,  or 38%  reflects a decrease of 34% in the price per  decatherm  of gas
purchased,  and a 10% reduction in the quantity of gas purchased, as a result of
the extremely warm winter.  Fluctuations  in utility gas costs  associated  with
firm gas  customers  have no impact on operating  results.  The current gas rate
structure of each of our gas  distribution  utilities  includes a gas adjustment
clause,  pursuant to which variations  between actual gas costs incurred and gas
cost  recoveries  are deferred and refunded to or collected  from customers in a
subsequent period.

<PAGE>

Operating Expenses

Operating  expenses  increased by $14.6 million,  or 7%, in the third quarter of
2002 compared to the same period last year. For the nine months ended  September
30, 2002,  operating  expenses  decreased by $21.0 million or 3% compared to the
corresponding   period   last  year.   Comparative   operating   expenses   were
significantly  impacted  by the  discontinuation  of goodwill  amortization.  In
January 2002, we adopted Statement of Accounting Standard ("SFAS") 142 "Goodwill
and Other  Intangible  Assets").  Goodwill  amortization in the gas distribution
segment for the three and nine months ended  September 30, 2001 was $8.9 million
and $26.6 million,  respectively.  Goodwill  amortization  for the twelve months
ended  December 31, 2001 was $35.6  million.  Excluding  the effects of goodwill
amortization,  operating expenses increased by $23.5 million and by $5.6 million
for the quarter and period ended September 30, 2002,  respectively,  compared to
the corresponding periods last year.

The  increase in  operating  expense for both the quarter and nine months  ended
September 30, 2002, is partly  attributable to the timing of certain  operations
and   maintenance   costs,  as  well  as,  an  increase  in  pension  and  other
postretirement  benefits.  The cost of these  benefits  has  increased  due to a
reduction in the return on plan assets,  as well as an increase in actual health
care costs. Further, depreciation expense, excluding 2001 goodwill amortization,
has  also  increased  as  a  result  of  the  continued  expansion  of  the  gas
distribution system.

Offsetting, to some extent, the increases in expenses noted above is a favorable
$7.4 million  adjustment to operating  taxes  recorded in the second  quarter of
2002 related to the reversal of excess tax reserves  established for the KeySpan
/ LILCO  merger and  subsequent  re-organization  in May 1998.  Further,  we are
currently  realizing cost saving  synergies as a result of early  retirement and
severance  programs  implemented  in the  fourth  quarter  of  2000.  The  early
retirement  portion of the  program was  completed  in 2000,  but the  severance
feature will continue through 2002

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.  In the third quarter of
2002,  Islander East Pipeline,  LLC received a certificate of public convenience
and  necessity  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.

<PAGE>

Subsequent to the timely receipt of approvals from the State of Connecticut, the
Islander  East  Pipeline is expected  to begin  operating  in late 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 the
remainder of 2002.)

Electric Services

The Electric  Services segment  primarily  consists of subsidiaries that own and
operate oil and gas fired electric  generating  plants in Queens (the Ravenswood
facility) 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)
   ------------------------------------------ -------------------- ------------------- -------------------- -------------------
                                                 Three Months        Three Months           Nine Months           Nine Months
                                                    Ended                 Ended                Ended                  Ended
                                                September 30,         September 30,        September 30,         September 30,
                                                    2002                  2001                  2002                  2001
   ------------------------------------------ -------------------- ------------------- -------------------- -------------------
   <S>                                                   <C>                <C>                 <C>                <C>
    Revenues                                          $   414,893          $  387,906         $  1,084,384         $ 1,089,231
    Purchased fuel                                        101,572              87,401              216,712             241,055
   ------------------------------------------ -------------------- ------------------- -------------------- -------------------
   Net Revenues                                           313,321             300,505              867,672             848,176
   ------------------------------------------ -------------------- ------------------- -------------------- -------------------
   Operating expenses
     Operations and maintenance                           149,682             153,881              481,732             465,787
     Depreciation                                          16,176              13,200               43,835              38,490
     Operating taxes                                       40,809              38,931              114,449             120,600
   ------------------------------------------ -------------------- ------------------- -------------------- -------------------
   Total Operating Expenses                               206,667             206,012              640,016             624,877
   ------------------------------------------ -------------------- ------------------- -------------------- -------------------
   Operating Income                                       106,654              94,493              227,656             223,299
   Other Income and (Deductions)                            6,624               2,026               15,995               6,526
   ------------------------------------------ -------------------- ------------------- -------------------- -------------------
   Earnings Before Interest and Taxes                 $   113,278           $  96,519           $  243,651          $  229,825
   ------------------------------------------ -------------------- ------------------- -------------------- -------------------
   Electric sales (MWH)*                                2,175,937           1,869,712            4,392,915           4,185,332
   Cooling Degree Days                                      1,094                 947                1,434               1,338
   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 by $12.8 million, or 4% and $19.5 million,
or 2% for the three and nine months ended  September  30, 2002,  compared to the
same periods in 2001.  Net  revenues for the quarter and period ended  September
30, 2002,  reflect revenues of $8.1 million and $9.4 million,  respectively from
our new  Glenwood  Landing and Port  Jefferson  electric  generating  facilities
located on Long Island.  The Glenwood  facility was placed in service on June 1,
2002,  while the Port Jefferson  facility was placed in service on July 1, 2002.

<PAGE>

These  facilities  add a combined  158 MW of  generating  capacity to  KeySpan's
electric portfolio.  The capacity of and energy produced by these facilities are
dedicated to LIPA under 25 year  contracts.  Net revenues  from the LIPA service
agreements and the Ravenswood facility for the quarter ended September 30, 2002,
remained  relatively  flat compared to the third  quarter of last year.  For the
nine months ended September 30, 2002,  higher  comparative net revenues from the
LIPA service  agreements  were mostly offset by lower  comparative  net revenues
from the Ravenswood facility.


Net revenues from the LIPA service agreements  increased by $4.4 million, or 2%,
and by $36.5  million or 6% for the quarter and nine months ended  September 30,
2002, respectively, 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 have no impact
on  earnings  since we record a similar  amount of costs in  operating  expense.
Excluding these third party  billings,  revenues for the quarter and nine months
ended  September  30, 2002  associated  with the LIPA  service  agreements  were
comparable to such revenues during the same period last year.

Net revenues  from the  Ravenswood  facility  were flat for the third quarter of
2002  compared to the same period in 2001.  Higher net revenues from the sale of
energy were entirely offset by lower capacity sales. While  "spark-spread"  (the
selling price of electricity less the cost of fuel) remained relatively constant
for the third  quarter of 2002  compared to the same  period  last year,  energy
sales  benefited  from a 16% increase in megawatt  hours sold as a result of the
hot weather  experienced  during the summer.  Measured in cooling  degree  days,
weather  during the peak  summer  months of July  through  September  2002,  was
approximately 16% warmer compared to last year.

Net revenues  from the  Ravenswood  facility  were $26.4  million,  or 9%, lower
during the nine months ended September 30, 2002,  compared to the same period in
2001.  Net revenues  from  capacity  sales  decreased 18% compared to last year,
while margins  associated  with the sale of electric  energy were 5% higher than
last year. Comparative energy sales benefited from a 5% increase in the megawatt
hours sold as a result of the hot summer weather offset, in part, by a reduction
in  "spark-spread".  Measured in cooling  degree days,  weather  during the nine
months ended  September  30,  2002,  was  approximately  7% warmer than the same
period last year.

The  decrease in  comparative  net  revenues  from  capacity  sales for both the
quarter and nine months  ended  September  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. However, in September 2002, the NYISO recognized a calculation flaw in
its revised  methodology.  This flaw  resulted in  insufficient  capacity  being
procured by the market,  as well as a reliability  concern.  Prior to the recent
2002/2003  winter  auction the NYISO  corrected the  calculation  methodology to
ensure  sufficient  capacity is  procured.  Elimination  of the flaw will ensure
compliance with New York State  Reliability  Rules. The Ravenswood  facility and
the NYISO energy market should benefit from this correction  since, as a result,
load serving entities,  such as electric  utilities,  should procure  sufficient
capacity  to  maintain  reliability  for  customers.   Further,  the  correction
addresses the lack of an appropriate price signal necessary to encourage greatly
needed new supply.

<PAGE>

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
KeySpan's  Annual  Report on Form 10K,  Item 7A.  Quantitative  and  Qualitative
Disclosures About Market Risk, as well as Item 3. of this Form 10Q for a further
discussion of these matters.)

Operating Expenses

Operating expenses for the quarter of 2002,  remained  consistent with the prior
year.  Lower  operating  and  maintenance  costs were offset by slightly  higher
depreciation and operating  taxes.  During the third quarter of 2002, we settled
certain  outstanding issues with LIPA and Consolidated Edison that resulted in a
$13.0  million  decrease  to  operating  expenses.  Partially  offsetting  these
favorable  settlements,  was an  increase in third party  costs.  As  previously
mentioned, these costs are fully recovered from LIPA. Operating expenses for the
nine months ended September 30, 2002 increased by $15.1 million, or 2% primarily
as a result of third party costs offset,  in part, by the  beneficial  impact of
settlements previously mentioned.

Other Income and Deductions

The increase of $4.6  million and $9.5 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 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 nine months ended  September  30,
2002,  the  subsidiaries  within the  Electric  Services  segment  have been net
"lenders"  to 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.

<PAGE>

Other Matters

As previously  mentioned,  both the Glenwood Landing and Port Jefferson electric
generating  facilities are fully operational.  Short-term financing was used for
the  construction  of  these  facilities,   but  various  financing  options  to
permanently  finance these  facilities are being  explored.  (See the discussion
under "Capital Expenditures and Financing" for more information on our financing
plans for 2002.) Further,  construction has begun on a new 250 MW combined cycle
generating  facility  at the  Ravenswood  facility  site.  The new  facility  is
expected to commence  operations in late 2003. The capacity and energy  produced
from this plant are anticipated to be sold into the NYISO energy markets. We are
also  progressing  through the siting process before the New York State Board on
Electric  Generation  Siting  and the  Environment  with a  proposal  to build a
similar 250 MW combined cycle electric generating facility on Long Island.

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  remain
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 required governmental approvals.

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  (formerly  owned by
LILCO)  to LIPA,  or the sale of some or all of these  plants  to other  private
operators.

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.

<PAGE>

The  table  below  highlights  selected  financial  information  for the  Energy
Services segment.
<TABLE>
<CAPTION>
                                                                                                                 (In Thousands)
   ------------------------------------------ -------------------- -------------------- ------------------- --------------------
                                              Three Months Ended   Three Months Ended   Nine Months Ended    Nine Months Ended
                                              September 30, 2002   September 30, 2001   September 30, 2002  September 30, 2001
   ------------------------------------------ -------------------- -------------------- ------------------- --------------------
  <S>                                                   <C>                  <C>                 <C>                 <C>
   Revenues                                            $  217,104           $  263,047          $  687,975           $  814,911
   Less: cost of gas and fuel                              45,809               81,768             157,694              326,943
   ------------------------------------------ -------------------- -------------------- ------------------- --------------------
   Net revenues                                           171,295              181,279             530,281              487,968
   Other operating expenses                               176,129              251,174             555,337              622,033
   ------------------------------------------ -------------------- -------------------- ------------------- --------------------
   Operating  Loss                                         (4,834)             (69,895)            (25,056)            (134,065)
   Other Income and (Deductions)                              379                  301               1,155                1,052
   ------------------------------------------ -------------------- -------------------- ------------------- --------------------
   Loss Before Interest and Taxes                     $    (4,455)          $  (69,594)         $  (23,901)          $ (133,013)
   ------------------------------------------ -------------------- -------------------- ------------------- --------------------
</TABLE>

Comparative  EBIT results for the three and nine months ended September 30, 2002
compared to 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 then existing contracts,  based upon our view
that  the  general  contracting  business  is not a  core  competency  of  these
companies.  (See KeySpan's 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 nine months ended
September 30, 2001, we incurred EBIT losses of $72.6 million and $133.7 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 nine months ended  September 30, 2002, we incurred EBIT losses
of $4.9 million and $8.2 million,  reflecting  increases in the estimates of and
costs to complete these contracts, and general and administrative expenses.

Excluding  the  results  of the former Roy Kay  companies,  the Energy  Services
segment  reflected a decrease in EBIT of $2.5 million and $16.4  million for the
three and nine months ended  September  30, 2002,  respectively  compared to the
corresponding  periods last year.  Revenues,  excluding  the Roy Kay  companies,
decreased  by $29.9  million  and $174.0  million  for the three and nine months
ended  September  30, 2002,  respectively,  while the cost of fuel  decreased by
$36.0 million and $169.3 million during the same time periods.  These  declines,
which for the most part offset each other, reflect the operations of our gas and
electric  marketing  subsidiary.  Beginning in 2002, this subsidiary focused its
marketing   efforts  on  higher  net  margin  customers  and  as  a  result  has
substantially decreased its customer base.

EBIT  results for the  Business  Solutions  group of  companies,  which  provide
mechanical  contracting,   plumbing,  engineering  and  consulting  services  to
commercial,  institutional,  and industrial customers,  improved by $7.1 million
and $6.3  million  for the three  and nine  months  ended  September  30,  2002,
respectively  compared to the same periods last year.  These  increases  reflect
additional volume and the timing of completion of certain contracts.

<PAGE>

Offsetting  these  increases  in EBIT are  decreases  of $7.3  million and $21.4
million  associated  with the Home Energy  Services  group of  companies.  These
companies  provide  residential and small commercial  customers with service and
maintenance of appliances,  as well as, the retail  marketing of natural gas and
electricity.  The following  factors  contributed  to the decreases in EBIT from
Home Energy Services:  (i) the continued  adverse impact of the down-turn in the
economy;   (ii)  cancellation  of  appliance  service  contracts;   (iii)  costs
associated  with the  closing of a service  center;  and (iv) an increase in the
reserve  for bad debts.  Comparative  EBIT  results in 2002  benefited  from the
elimination of goodwill amortization,  which for the three and nine months ended
September 30, 2001 amounted to $1.8 million and $5.8 million, respectively.

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 and
realize synergy savings.

Energy Investments

The  Energy  Investment  segment  consists  of 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 a 67%
equity interest in Houston  Exploration,  as well as a wholly-owned  subsidiary,
KeySpan  Exploration  and  Production,  LLC. In line with our stated strategy of
exploring the monetization or diversiture of certain non-core assets, in October
2002, we monetized a portion of our assets in the joint venture drilling program
with Houston  Exploration that was created in 1999. We received $26.5 million in
cash from Houston  Exploration  for 18.6 Bcfe of  estimated  proved and probable
reserves.  The proceeds will be used to pay down short-term  debt;  there was no
earnings impact from this transaction.

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

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

                                                  Three Months Ended  Three Months Ended    Nine Months Ended   Nine Months Ended
                                                  September 30, 2002  September 30, 2001   September 30, 2002   September 30, 2001
   ---------------------------------------------- ------------------- -------------------- -------------------- -------------------
  <S>                                                       <C>                 <C>                  <C>                 <C>
   Revenues                                                $  86,464           $   82,362           $  249,452          $  318,093
   Depletion and amortization expense                         44,880               35,697              130,766             102,749
   Other operating expenses                                   15,230               12,471               43,053              44,915
   ---------------------------------------------- ------------------- -------------------- -------------------- -------------------
   Operating Income                                           26,354               34,194               75,633             170,429
   Other Income and (Deductions)*                             (5,079)              (7,407)             (15,091)            (34,169)
   ---------------------------------------------- ------------------- -------------------- -------------------- -------------------
   Earnings Before Interest and Taxes*                     $  21,275           $   26,787           $   60,542          $  136,260
   --------------------------------------------- ------------------- -------------------- -------------------- -------------------
   Natural gas and oil production (Mmcf)                      26,913               23,265               79,641              69,947
   Natural gas price (per Mcf) realized                       $ 3.14               $ 3.50               $ 3.08              $ 4.53
   Natural gas price  (per Mcf) unhedged                      $ 3.00               $ 2.72               $ 2.80              $ 4.71
   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 which is included in
Other Income and  (Deductions).  Gas reserves and  production are stated in BCFe
and Mmcfe, which includes equivalent oil reserves.

<PAGE>

Earnings Before Interest and Taxes

The decrease in EBIT of $5.5 million for the third quarter of 2002,  compared to
the corresponding  quarter last year primarily reflects an increase in operating
costs of $11.9 million, or 25%, offset in part by a $4.1 million, or 5% increase
in revenues.  The increase in operating expenses is primarily due to an increase
in  depletion  and  amortization  expense  as a  result  of a  16%  increase  in
production volumes.  The increase in revenues reflects the benefits derived from
production  volume  increases,  offset in part by a  decrease  of 10% in average
realized gas prices  (average  wellhead price received for production  including
realized hedging gains and losses).  The decrease in average realized gas prices
reflects  lower hedging gains  realized  during the quarter ended  September 30,
2002, compared to the same quarter last year.

The  decrease  in EBIT of  $75.7  million,  or 56% for  the  nine  months  ended
September 30, 2002, compared to the same period last year reflects a significant
reduction in revenues and, to a lesser degree, an increase in operating expenses
associated with higher levels of production.  Revenues for the nine months ended
September 30, 2002, compared to the same period in 2001, were adversely impacted
by a 32% decline in average realized gas prices.  The adverse effect on revenues
resulting from the decline in average  realized gas prices was partially  offset
by an increase of 14% in production  volumes.  The  depreciation,  depletion and
amortization  rate was $1.64 per mcf for the nine  months  ended  September  30,
2002,  compared to $1.44 per mcf for the same period in 2001,  reflecting higher
finding and development costs together with the addition of fewer new reserves.

The  average  realized  gas price in the third  quarter  of 2002 was 105% of the
average  unhedged natural gas price. The average realized gas price for the nine
months ended  September  30, 2002 was 110% of the average  unhedged  natural gas
price during that period. The average realized gas price in the third quarter of
2001 was 129% of the  average  unhedged  natural  gas price,  while the  average
realized gas price for the nine months ended  September  30, 2001 was 96% of the
average unhedged natural gas price.  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 these  derivative
instruments  during the nine  months  ended  September  30,  2002  resulted in a
comparative  benefit  to  revenues  of  $32.3  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 there is a  significant  downward
revisions in estimated proved reserves.

<PAGE>

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)
   ------------------------------------------- -------------------- ------------------- -------------------- --------------------
                                               Three Months Ended   Three Months Ended   Nine Months Ended    Nine Months Ended
                                               September 30, 2002   September 30, 2001  September 30, 2002   September 30, 2001
   ------------------------------------------- -------------------- ------------------- -------------------- --------------------
  <S>                                                    <C>                 <C>                   <C>                 <C>
   Revenues                                              $  23,793          $   22,436           $   63,366            $  73,627
   Operation and maintenance expense                        10,915              18,562               44,749               51,698
   Other operating expenses                                  4,633               4,486               13,205               12,268
   ------------------------------------------- -------------------- ------------------- -------------------- --------------------
   Operating Income (Loss)                                   8,245               (612)                5,412                9,661
   Other Income and (Deductions)                             2,690               3,030               11,677                9,158
   ------------------------------------------- -------------------- ------------------- -------------------- --------------------
   Earnings Before Interest and Taxes                    $  10,935           $   2,418            $  17,089            $  18,819
   ------------------------------------------- -------------------- ------------------- -------------------- --------------------
</TABLE>

The increase in EBIT for the third  quarter of 2002 compared to the same quarter
last  year,   reflects   the  timing  of  certain   expenses   associated   with
technology-related  investments,  as well as lower comparative losses associated
with these investments. The decrease in EBIT for the nine months ended September
30,  2002,  is  primarily  due to the  operations  of  KeySpan  Canada 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 2002,  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 in 2002 as
a result of lower demand for LNG due to the extremely warm winter weather. These
decreases  to  comparative  EBIT  results  were  substantially  offset  by lower
comparative losses associated with certain technology-related investments.

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 nine months ended  September
30,  2002,  compared  to  the  corresponding  period  last  year,  is  primarily
attributable to lower interest and income tax payments, as well as to a decrease
in cash  payments  for  natural  gas  purchased  for  inventory.  As  previously
mentioned,  interest  payments have  decreased due to the  beneficial  effect of
interest  rate  swaps,  as  well  as to  lower  interest  rates  on  outstanding
commercial paper.  State and federal tax payments were lower for the nine months

<PAGE>

ended  September 30, 2002,  compared to the same period last year, as KeySpan is
currently in a refund position with regards to such taxes.  Further,  due to the
extremely  warm  weather  experienced  during the past winter and the  resulting
higher  inventory  levels,  we  purchased  a lower  quantity  of natural gas for
storage  purposes so far this year than we did during the  corresponding  period
last year, and at lower prices.  As mentioned  earlier,  fluctuations in utility
gas costs  have no impact  on  operating  results,  since the  current  gas rate
structure of each of our gas  distribution  utilities allow for full recovery of
these costs. Operating cash flow from gas exploration and production activities,
however,  was adversely impacted by significantly  lower realized gas prices for
the nine months ended September 30, 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  consolidated  revenues are
derived from the operations of businesses  within the Electric Services segment,
that are  largely  dependent  upon two  large  customers  - LIPA and the  NYISO.
Accordingly,  our cash flows are  dependent  upon the timely  payment of amounts
owed to us by these customers.

In July 2002,  KeySpan renewed its 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
the $1.3 billion commercial paper program. The fees for the facility are subject
to a ratings-based  grid, with an annual fee of .075% on the total amount of the
revolving  facility.  The credit  agreement  allows for KeySpan to borrow  using
several different types of loans; specifically,  Eurodollar loans, 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 September  30, 2002,  we had cash and  temporary  cash  investments  of $53.9
million.  During the nine months  ended  September  30, 2002,  we repaid  $519.2
million of  commercial  paper and, at  September  30,  2002,  $529.2  million of
commercial paper was outstanding at a weighted average annualized  interest rate
of 1.87%.  We had the ability to borrow up to an  additional  $770.8  million at
September 30, 2002 under the commercial paper program.

Under the terms of the credit facility,  KeySpan's debt-to-total  capitalization
ratio  reflects  80% equity  treatment  for the MEDS Equity  Units issued in May
2002;  further the $425 million  Ravenswood Master Lease is 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 September 30, 2002, consolidated  indebtedness,  as
calculated under the terms of the new credit facility, was 63.6% of consolidated
capitalization.  Violation of this covenant  could result in the  termination of
the credit facility and the required  repayment of amounts borrowed  thereunder,
as well as possible cross defaults under other debt agreements.  (See discussion
under "Capital  Expenditures and Financing for an explanation of the MEDS Equity
Units and Ravenswood Master Lease.)

<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.

Under the Houston  Exploration  credit facility,  interest on base rate loans is
payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater
of the Federal  funds rate plus .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,  (i)
maintain an interest  coverage ratio of at least 3.00 to 1.00 of earnings before
interest,  taxes and depreciation  ("EBITDA") to cash interest;  (ii) maintain a
total debt to EBITDA of not more than a ratio of 3.50 to 1.00;  and (iii)  hedge
no more than 70% of natural gas production during any 12-month period.

During the nine months ended September 30, 2002,  Houston  Exploration  borrowed
$46.0  million  under its prior credit  facility and repaid  $43.0  million.  At
September  30,  2002,  $147  million of  borrowings  remained  outstanding  at a
weighted average annualized  interest rate of 3.38%; $103.0 million of borrowing
capacity was available.

KeySpan Canada has two revolving loan agreements with financial  institutions in
Canada. Repayments under these agreements totaled approximately US $20.5 million
for  the  nine  months  ended   September  30,  2002.  At  September  30,  2002,
approximately US $155.0 million was outstanding at a weighted average annualized
interest rate of 3.15%.  KeySpan  Canada  currently has available  borrowings of
approximately  US $49.8 million.  These  revolving  credit  agreements have been
extended without modification through December 31, 2002.

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) $127.2 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
$95.0 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) $63.2 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  $173.9  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)
---------------------------------------- -------------------- ------------------
                                          Nine Months Ended   Nine Months Ended
                                         September 30, 2002   September 30, 2001
---------------------------------------- -------------------- ------------------
Gas Distribution                                  $  294,774          $  219,137
Electric Services                                    290,790             138,272
Energy Investments                                   242,097             301,974
Energy Services                                        8,319               9,111
---------------------------------------- -------------------- ------------------
                                                  $  835,980          $  668,494
---------------------------------------- -------------------- ------------------


<PAGE>


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 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 the  joint  venture  with  Houston
Exploration, as well as costs related to Canadian affiliates.

At September 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
$183.0 million.

Construction  expenditures  are reviewed on an ongoing basis and can be affected
by timing, scope and changes in investment opportunities.

Financing

At December  31,  2001,  KeySpan 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  the  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 the  financing  authority  under PUHCA by $700 million,
thereby  matching  the shelf  availability.  We  anticipate  a decision  on this
request by the SEC by year-end.

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.

<PAGE>

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.

During the first half of 2003, we intend to issue  approximately $150 million of
either taxable or tax-exempt  long-term 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 an additional  $200 to $300 million of medium-term  debt in the fourth
quarter of 2002 or early 2003 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 had several  interest rate swap agreements on a portion of our existing
fixed rate medium-term and long-term debt that  effectively  changed the debt to
floating rate debt.  These swap  agreements  qualified for hedge  accounting and
were  completed  with several major  financial  institutions  in order to reduce
credit risk.  In early  November  2002,  we  terminated  two interest  rate swap
agreements with an aggregate  notional amount of $1.0 billion and received $81.0
milliom from our swap counter-parties. (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 the 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.  KeySpan  has  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.



<PAGE>


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.

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 late  2002,  and be
effective April 1, 2003. It is possible that KeySpan may be required to classify
the lease  under  which  the  Ravenswood  facility  is  operated  as debt on the
Consolidated Balance Sheet at an amount generally equal to fair market value. As
previously  mentioned,  under the terms of our credit  facility  the  Ravenswood
Master Lease is considered  debt in the ratio of  debt-to-total  capitalization.
Further, we may be required to record an asset on the Consolidated Balance Sheet
for an amount generally equal to the fair market value of the leased assets.  At
this time,  we believe  that the fair  market  value of the leased  assets is in
excess of the original acquisition cost. 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,  Standard and Poor's rating agency, and FitchRatings
have rated our long-term debt as follows: (i) KeySpan's long-term debt A3, A and
A-, respectively;  (ii) KEDNY's long-term debt A2, A+ and A+, respectively;  and
(iii)  KEDLI's  long-term  debt A2,  A+ and A,  respectively.  Moody's  Investor
Services and Standard and Poor's  rating  agency rated Boston Gas  Company's and
Colonial Gas Company's  long-term debt A2 and A,  respectively.  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 September 30, 2002:
<TABLE>
<CAPTION>
                                                                                               (In Thousands)
   ---------------------------------- ---------------- ------------------ -------------------- ----------------------

   Contractual Obligations                   Total           1-3 Years           4-5 Years           After 5 Years
   ---------------------------------- ---------------- ------------------ -------------------- ----------------------
  <S>                                     <C>                  <C>                <C>                    <C>
   Long-Term Debt                     $     5,228,070  $         486,151  $         1,212,333  $           3,529,586

   Capital Lease Obligations                   13,912              2,327                2,031                  9,554

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

   Total Contractual
      Cash Obligations                $     5,875,295  $         750,431  $         1,379,805  $           3,745,059
   ---------------------------------- ---------------- ------------------ -------------------- ----------------------

   Commercial Paper                   $       529,228          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  the  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 and other  construction  services by
subsidiaries in the 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, KeySpan 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 was 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,  was to 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.

KeySpan records  goodwill on purchase  transactions,  representing the excess of
acquisition  cost over the fair value of net  assets  acquired.  In testing  for
goodwill  impairment  under  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
may differ from our projections.


<PAGE>


During the  second  quarter  of 2002,  we  completed  our  analysis  for all the
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. We will
conduct an annual review (in the fourth quarter) 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 had interest rate swap agreements in which  approximately $1.3
billion of fixed rate debt was effectively  converted to floating rate debt. The
fair value of these  derivative  instruments  was  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
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") 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 September 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 a write
down to the full cost pool will be required  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 KeySpan's 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
Utilities 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 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 previously in effect for KEDNY, KEDLI and Boston Gas Company have all
expired. The continued  application of SFAS 71 to record the activities of these
subsidiaries  is contingent upon the actions of regulators with regard to future
rate plans. We 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 DTE that we may file a
base rate case and a  performance  based rate plan for the Boston Gas Company to
replace the plan that  expired 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.  This  request  was  denied  by the DTE in  early
September 2002.

The rate agreement for KEDLI expired in November 2000 and the rate agreement for
KEDNY  expired  September  30, 2002.  Under the terms of these  agreements,  gas
distribution rates and all other provisions will remain in effect. At this time,
we  are  currently  evaluating  various  options  that  may be  available  to us
regarding all of our gas  distribution  rate plans 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
KeySpan's 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".


<PAGE>


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 (a $700 million  increase above
the  existing  authorization),  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 September 30, 2002 our consolidated common equity was 33% of
our consolidated capitalization, including commercial paper.

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  $200.9 million
and we have recorded a related  liability for such amount. We have also recorded
an additional $41.2 million liability,  representing the estimated environmental
cleanup costs related to a former coal tar processing  facility.  Further, as of
September 30, 2002, we have  expended a total of $60.8  million.  (See Note 4 to
the Consolidated Financial Statements, "Environmental Matters").

<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,  electric  generation,  and  industrial
customers and the provision of retail access  services to gas marketers,  by our
regulated gas  businesses;  the sale of commodities and services to LIPA and the
NYISO;  the sale of gas  power  and  services  to our  retail  customers  by our
unregulated  energy  service  businesses;  entering  into  financial  and energy
derivative contracts with energy marketing companies and financial institutions;
and the sale of gas, natural gas liquids,  oil and processing services to energy
marketing and oil 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.

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;

<PAGE>

     -    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;

     -    credit  worthiness of  counter-parties  to derivative  instruments and
          commodity contracts;

     -    retention of key personnel;

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

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

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

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

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

     -    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

KeySpan  is  subject  to various  risks and  uncertainties  associated  with its
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,  KeySpan is 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  KeySpan's   operations.
Additionally,  see  KeySpan's  Annual  Report  on Form  10K for the  year  ended
December 31, 2001 Item 7A "Quantitative and Qualitative Disclosures About Market
Risk".

<PAGE>

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.

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.


<PAGE>


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 $1,000/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.

Commodity Contracts and Electric Derivative Instruments

From time to time KeySpan has utilized derivative financial instruments, such as
futures,  options and swaps,  for the purpose of hedging  exposure to  commodity
price risk and to hedge the cash flow  variability  associated with a portion of
peak electric  energy sales.  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  October  31,  2002,  Houston
Exploration  has  hedged  approximately  65%  of its  estimated  2002  and  2003
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 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 $14.6 million.

KeySpan has also employed standard NYMEX gas futures  contracts,  as well as oil
swap derivative  contracts,  to hedge the cash flow  variability of a portion of
forecasted  purchases  of natural  gas and fuel oil that will be consumed at the
Ravenswood  facility.  Natural  gas  basis  swaps  are  also  utilized  to hedge
forecasted  purchases of natural gas transportation.  The maximum length of time
over which we have hedged cash flow variability  associated with: (i) forecasted
purchases of natural gas is October 2003; (ii) forecasted  purchases of fuel oil
is  through  April  2004;  and  (iii)   forecasted   purchases  of  natural  gas
transportation  is through  December 2003. We used standard NYMEX futures prices
to value the gas futures contracts and industry published oil indices for number
6 grade fuel oil to value the oil swap contracts.  The estimated amount of gains
associated with all such derivative instruments that are reported in Accumulated
Other  Comprehensive  Income  and  that are  expected  to be  reclassified  into
earnings over the next twelve months is $4.1 million.

Our retail gas and electric marketing subsidiary,  our domestic gas distribution
operations and KeSpan Canada  employed  NYMEX natural gas futures  contracts and
natural gas swaps to lock-in a price for expected  future natural gas purchases.
As applicable,  we used standard  NYMEX futures prices and relevant  natural gas
indices to value the  outstanding  contracts.  The  maximum  length of time over
which we have hedged such cash flow  variability  is through  October 2003.  The
estimated amount of gains  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 $2.5 million.


<PAGE>


We have also engaged in the use of  cash-settled  swap  instruments to hedge the
cash flow  variability  associated  with a portion of 2002 peak electric  energy
sales from the Ravenswood  facility.  All hedge positions for the summer of 2002
have been settled. We currently have a number of remaining  derivatives that are
employed  to  hedge  cash  flow  variability  through  December  2002.  We  used
NYISO-location  zone published indices to value these  outstanding  derivatives.
The estimated amount of gains  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 $2.4 million.

KeySpan  Canada also has  employed  electricity  swap  contracts  to lock-in the
purchase price of electricity needed to operate its gas processing plants. These
contracts  are not  exchange-  traded and local  published  indices were used to
value these  outstanding swap agreements.  The maximum length of time over which
we have  hedged  such  cash flow  variability  is  through  December  2003.  The
estimated amount of losses associated with such derivative  instruments that are
reported in Accumulated Other  Comprehensive  Income and that are expected to be
reclassified into earnings over the next twelve months is $1.7 million.



<PAGE>



The following  tables set forth selected  financial data  associated  with these
derivative financial  instruments noted above that were outstanding at September
30, 2002.

<TABLE>
<CAPTION>
-------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
                                   Year of      Volumes                                  Fixed Price      Current      Fair Value
       Type of Contract           Maturity        mmcf        Floor $     Ceiling $          $            Price $        ($000)
-------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
              Gas
<S>                               <C>          <C>           <C>           <C>         <C>             <C>             <C>
Collars                             2002         14,720        3.56          5.14            -          3.69 - 4.32      (1,141)
                                    2003         32,350        3.34          4.97            -          3.90 - 4.40      (2,498)

Swaps / Futures-Short
   Natural Gas                      2002          3,191          -            -             3.01        3.69 - 4.32      (2,662)
                                    2003         15,208          -            -             3.19        3.90 - 4.40     (12,394)

Swaps / Futures-Long
   Natural Gas                      2002         2,990           -            -         2.68 - 4.24     3.90 - 4.32       1,227
                                    2003         8,210           -            -         3.10 - 4.35     3.90 - 4.40       2,359
-------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
                                                76,669                                                                  (15,109)
-------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
       Type of Contract             Year of          Volumes                                                         Fair Value
                                   Maturity          Barrels           Fixed Price $          Current Price $          ($000)
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
             Oil
<S>                                  <C>            <C>               <C>                    <C>                      <C>
Swaps - Long Fuel Oil                 2002            146,994           19.75 - 26.40          28.65 - 29.00            1,024
                                      2003            307,822           20.10 - 26.72          23.01 - 28.96            1,613
                                      2004              5,404           20.50 - 23.70          22.84 - 23.33                7
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
                                                      460,220                                                           2,644
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
</TABLE>

<TABLE>
<CAPTION>
-------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
    Type of Contract         Year of                                                  Current       Estimated         Fair Value
                             Maturity              MWh     Fixed Profit /Price $      Price $        Profit $           ($000)
-------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
       Electricity
<S>                           <C>               <C>           <C>                    <C>         <C>                 <C>
Tolling Arrangements           2002               102,400          26.00                 -         1.61 - 3.85          2,383

Swaps - Long                   2002                17,664      56.07 - 57.33           30.87            -                (429)
                               2003                70,080      56.07 - 57.33           29.61            -              (1,791)
-------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
                                                  190,144                                                                 163
-------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
</TABLE>

<PAGE>


NYMEX  futures  are also used to  economically  hedge the cash flow  variability
associated  with the  purchase  of fuel for a  portion  of our  fleet  vehicles.
Further,  KeySpan  Canada has a  portfolio  of  financially-settled  natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i)  synthetically  fix the price that is paid or received by
KeySpan  Canada for  certain  physical  transactions  involving  natural gas and
natural gas liquids and (ii) transfer the price exposure of such  instruments to
other trading partners.  These derivative  financial  instruments do not qualify
for hedge accounting  under SFAS 133. At September 30, 2002,  these  instruments
had a favorable net mark-to-market value of $0.4 million,  which was recorded on
the Consolidated Balance Sheet and recorded to earnings for the quarter and nine
months ended September 30, 2002.

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 use natural gas swap contracts, with offsetting positions in fuel
oil  swap  contracts  of  equivalent   energy  value,  to  hedge  the  cash-flow
variability  of specified  portions of gas  purchases and sales.  Currently,  no
derivative  transactions  outstanding  correspond to this particular  price risk
strategy, although we intend to enter into derivative instruments of this nature
during the fourth quarter of 2002 if market conditions 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  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 reduce the
variability  of the purchase  price of natural gas to be sold to regulated  firm
gas sales customers,  the accounting for these derivative instruments is subject
to SFAS 71.  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  table sets forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at September 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>
Options                               2002                   7,980       3.85 - 4.50                4.23                  1,549
                                      2003                  12,960       3.85 - 4.50                4.27                  2,946

Swaps - Long                          2002                     300           4.11                   4.24                     42
                                      2003                     600           4.11                   4.21                     59
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
                                                            21,840                                                        4,596
------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
</TABLE>


<PAGE>

Other  Commodity  Derivative  Instruments:  On  April  1,  2002  we  implemented
Derivative  Implementation  Group  (DIG)  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 the exemption  (as normal  purchase and normal sales)
of 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. At September 30,
2002, the fair value of these contracts was $2.0 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 have been recorded as a Regulatory  Asset or
Regulatory Liability on the Consolidated Balance Sheet.

Interest  Rate  Derivative  Instruments:  At September 30, 2002, we had interest
rate swap agreements in which  approximately $1.3 billion of fixed rate debt had
been  synthetically  modified  to  floating  rate  debt.  Under the terms of the
agreements,  we received the fixed coupon rate  associated  with these bonds and
paid the  counter-parties a variable interest rate that was reset on a quarterly
basis.  These swaps were  designated  as  fair-value  hedges and  qualified  for
"short-cut"  hedge accounting  treatment under SFAS 133. Through the utilization
of these  agreements,  we reduced recorded interest expense by $30.5 million for
the nine months ended September 30, 2002.

In early November 2002, we terminated two interest rate swap  agreements with an
aggregate  notional  amount of $1.0 billion and received  $81.0 million from our
swap  counter-parties,  of which $23.0 million represents accrued swap interest.
The  difference  between  the  termination  settlement  amount and the amount of
accrued  swap  interest,  $58.0  million,  will be  amortized to earnings (as an
adjustment to interest  expense) on a level yield basis over the remaining lives
of the  originally  hedged debt  obligations.  The remaining  swap,  which has a
notional amount of $270.0  million,  will continue to be accounted for as a fair
value hedge.

The table  below  summarizes  selected  financial  data  associated  with  these
derivative  financial  instruments  that were outstanding at September 30, 2002.
The fair values of these derivative  instruments were provided to us by our swap
counter-parties  and represent the present value of expected  future  cash-flows
associated with such transactions.


<PAGE>



The table  below  summarizes  selected  financial  data  associated  with  these
derivative financial instruments that were outstanding at September 30, 2002.
<TABLE>
<CAPTION>
-------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
                                                                                                   Average Variable
                                        Maturity Date of     Notional Amount       Fixed Rate          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%             4.250%              55,077

Medium Term Notes                             2006               500,000             6.150%             3.590%              37,145

Long Term Notes                               2023               270,000             8.200%             3.770%               6,843
-------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
                                                               1,270,000                                                    99,065
-------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
</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.

Weather  Derivatives:  The utility  tariffs  associated with the New England gas
distribution operations do not contain a weather normalization  adjustment. As a
result,  fluctuations  from normal  weather may have a  significant  positive or
negative  effect on the results of these  operations.  To mitigate the effect of
fluctuations  from normal weather on our financial  position and cash flows,  we
entered into weather collars during the quarter ended September 30, 2002.  These
derivatives will hedge  approximately  60% of expected gas throughput of the New
England gas distribution  companies during the November 2002 - March 2003 winter
season. The collars have been established with a ceiling that reflects 1% colder
than  normal  weather and a floor that  reflects 7% warmer than normal  weather.
KeySpan  will be required  to make  payment to its  counter-parties  when actual
weather  experienced  during the November  2002 - March 2003 time frame is 1% or
more colder than normal,  based on the 1975 - 1995 20 year avergae. In the event
that actual weather is 7% or more warmer than normal the counter-parties will be
required to make payment to KeySpan.  These derivatives will be accounted for by
applying the "intrinsic value method" and are outside the scope of SFAS 133.

Derivative  contracts  are  primarily  used to manage  exposure  to market  risk
arising  from changes in commodity  prices and interest  rates.  In the event of
nonperformance by a counter-party to a 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  KeySpan's  derivative  contracts  are with
investment grade companies.


<PAGE>


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

Item 1.  Legal Proceedings

See Note 10 to the Financial Statements "Legal Matters"

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Within  the 90 days prior to the date of this  report,  KeySpan  carried  out an
evaluation,  under  the  supervision  and with the  participation  of  KeySpan's
management,  including  KeySpan's  Chief  Executive  Officer and Chief Financial
Officer,  of  the  effectiveness  of  the  design  and  operation  of  KeySpan's
disclosure controls and procedures. KeySpan's disclosure controls and procedures
are designed to ensure that  information  required to be disclosed by KeySpan in
its  periodic SEC filings is recorded,  processed  and reported  within the time
periods specific in the SEC's rules and forms.  Based upon that evaluation,  the
Chief  Executive  Officer and Chief Financial  Officer  concluded that KeySpan's
disclosure  controls and  procedures  are  effective in timely  alerting them to
material   information   relating  to  KeySpan   (including   its   consolidated
subsidiaries) required to be included in KeySpan's periodic SEC filings.

Changes In Internal Controls

There were no  significant  changes in KeySpan's  internal  controls or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation.

Item 6.  Exhibits and Reports on Form 8-K

(a)        Exhibits

10.1*Second  Amendment  dated as of June 26, 2002, to the  Employment  Agreement
     dated September 10, 1998, between KeySpan  Corporation and Robert B. Catell

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  KeySpan's  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 July2, 2002.

In  KeySpan's  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,  our
earnings for the quarter ended June 30, 2002.

In  KeySpan's  report on Form 8-K dated  August 14,  2002,  we reported  that on
August 12, 2002, in  accordance  with SEC file No. 4-460 and pursuant to Section
21(a)(1) of the Securities Exchange Act of 1934, the Chief Executive Officer and
Chief  Financial  Officer of KeySpan  executed sworn  statements  which had been
submitted to the Securities and Exchange Commission.

In KeySpan's  report on Form 8-K dated October 24, 2002, we reported that we had
issued a press release on October 24, 2002, concerning,  among other things, our
earnings for the quarter ended September 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:  November 7, 2002                       /s/ Gerald Luterman
                                             ---------------------------
                                             Gerald Luterman
                                             Executive Vice President and
                                             Chief Financial Officer



Date:  November 7, 2002                      /s/ Ronald S. Jendras
                                             ---------------------------
                                             Ronald S. Jendras
                                             Vice President, Controller and
                                             Chief Accounting Officer


<PAGE>

Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities and Exchange
                                  Act of 1934


     I, Robert B. Catell, certify that:

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

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

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

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

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

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

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

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

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


<PAGE>


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

     6. The registrant's other certifying  officers and I have indicated in this
quarterly  report  whether or not there  were  significant  changes in  internal
controls or in other factors that could  significantly  affect internal controls
subsequent to the date of our most recent  evaluation,  including any corrective
actions with regard to significant deficiencies and material weaknesses.


Date: November 7, 2002



                                            /s/Robert B. Catell
                                            -------------------
                                            Robert B. Catell
                                            Chairman of the Board of Directors
                                            and Chief Executive Officer




<PAGE>

               Certification Pursuant to Rule 13a-14 and 15d-14 of
                     the Securities and Exchange Act of 1934


     I, Gerald Luterman, certify that:

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

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

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

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

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

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

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

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

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


<PAGE>


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

     6. The registrant's other certifying  officers and I have indicated in this
quarterly  report  whether or not there  were  significant  changes in  internal
controls or in other factors that could  significantly  affect internal controls
subsequent to the date of our most recent  evaluation,  including any corrective
actions with regard to significant deficiencies and material weaknesses.


Date: November 7, 2002



                                               /s/Gerald Luterman
                                               ------------------
                                               Gerald Luterman
                                               Executive Vice President and
                                               Chief Financial Officer