UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549

                                    FORM 10-Q

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

                For the quarterly period ended September 30, 2003

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

                        For the Transition period from _____ to____

                         Commission file number 1-14161

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

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

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

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

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

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

                      APPLICABLE ONLY TO CORPORATE ISSUERS:

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

     Class of Common Stock                       Outstanding at October 15, 2003
     ---------------------                       -------------------------------
         $.01 par value                                   159,060,100

<PAGE>


                      KEYSPAN CORPORATION AND SUBSIDIARIES

                                      INDEX
                                      -----

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

Item 1. Financial Statements

         Consolidated Balance Sheet -
         September 30, 2003 and December 31, 2002                         3

         Consolidated Statement of Income -
         Three and Nine months Ended September 30, 2003 and 2002          5

         Consolidated Statement of Cash Flows -
         Nine months Ended September 30, 2003 and 2002                    6

         Notes to Consolidated Financial Statements                       7

Item 2. Management's Discussion and Analysis of Financial
         Condition and Results of Operations                             35

Item 3. Quantitative and Qualitative Disclosures
         About Market Risk                                               68

Item 4. Controls and Procedures                                          73


                           Part II.   OTHER INFORMATION

Item 1. Legal Proceedings                                                73

Item 6. Exhibits and Reports on Form 8-K                                 73

Signatures                                                               75



                                       2
<PAGE>

<TABLE>
<CAPTION>
                           CONSOLIDATED BALANCE SHEET
                                   (Unaudited)
-----------------------------------------------------------------------------------------
(In Thousands of Dollars)                      September 30, 2003       December 31, 2002
-----------------------------------------------------------------------------------------

ASSETS
<S>                                                   <C>                     <C>
Current Assets
   Cash and temporary cash investments             $      118,051        $       170,617
   Accounts receivable                                  1,000,534              1,122,022
   Unbilled revenue                                       227,554                473,060
   Allowance for uncollectible accounts                   (70,306)               (63,029)
   Gas in storage, at average cost                        522,736                297,060
   Material and supplies, at average cost                 120,655                113,519
   Other                                                   88,370                 93,980
                                            ---------------------------------------------
                                                        2,007,594              2,207,229
                                            ---------------------------------------------

Investments and  Other                                    292,587                265,977

Property
   Gas                                                  6,397,706              6,124,281
   Electric                                             2,155,736              1,974,352
   Other                                                  400,953                394,374
   Accumulated depreciation                            (2,941,551)            (2,740,516)
   Gas exploration and production, at cost              2,788,884              2,438,998
   Accumulated depletion                               (1,108,826)              (973,889)
                                            ---------------------------------------------
                                                        7,692,902              7,217,600
                                            ---------------------------------------------

Deferred Charges
   Regulatory assets                                      475,748                438,516
   Goodwill, net of amortization                        1,816,434              1,789,751
   Other                                                  714,783                695,233
                                            ---------------------------------------------
                                                        3,006,965              2,923,500
                                            ---------------------------------------------

Total Assets                                       $   13,000,048        $    12,614,306
                                            =============================================
-----------------------------------------------------------------------------------------
</TABLE>

        See accompanying Notes to the Consolidated Financial Statements.


                                       3
<PAGE>

<TABLE>
<CAPTION>
                           CONSOLIDATED BALANCE SHEET
                                   (Unaudited)
--------------------------------------------------------------------------------------------
(In Thousands of Dollars)                          September 30, 2003     December 31, 2002
--------------------------------------------------------------------------------------------

LIABILITIES AND CAPITALIZATION
<S>                                                         <C>                  <C>
Current Liabilities
    Current redemption of long-term debt               $        11,417      $        11,413
    Accounts payable and other liabilities                     893,045            1,061,649
    Commercial paper                                           644,400              915,697
    Dividends payable                                           72,162               64,714
    Taxes accrued                                              139,749               51,276
    Customer deposits                                           39,529               38,387
    Interest accrued                                            99,254               77,092
                                                --------------------------------------------
                                                             1,899,556            2,220,228
                                                --------------------------------------------

Deferred Credits and Other Liabilities
    Regulatory liabilities                                     102,582               84,479
    Deferred income tax                                        976,358              877,013
    Postretirement benefits and other reserves                 795,437              759,731
    Other                                                      164,202              189,912
                                                --------------------------------------------
                                                             2,038,579            1,911,135
                                                --------------------------------------------

Commitments and Contingencies (See Note 8)                           -                    -

Capitalization
    Common stock                                             3,482,456            3,005,354
    Retained earnings                                          557,121              522,835
    Other comprehensive income                                 (68,101)            (108,423)
    Treasury stock                                            (398,190)            (475,174)
                                                --------------------------------------------
         Total common shareholders' equity                   3,573,286            2,944,592
    Preferred stock                                             83,697               83,849
    Long-term debt                                           4,927,423            5,224,081
                                                --------------------------------------------
Total Capitalization                                         8,584,406            8,252,522
                                                --------------------------------------------

Minority Interest in Subsidiary Companies                      477,507              230,421
                                                --------------------------------------------
Total Liabilities and Capitalization                   $    13,000,048      $    12,614,306
                                                ============================================
--------------------------------------------------------------------------------------------
</TABLE>

        See accompanying Notes to the Consolidated Financial Statements.



                                       4
<PAGE>

<TABLE>
<CAPTION>
                        CONSOLIDATED STATEMENT OF INCOME
                                   (Unaudited)
------------------------------------------------------------------------------------------------------------------------------
                                                                  Three Months Ended                 Nine Months Ended
                                                                     September 30,                    September 30,
(In Thousands of Dollars, Except Per Share Amounts)              2003             2002             2003             2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>             <C>               <C>               <C>
Revenues
     Gas Distribution                                      $     405,777     $    334,031    $    2,970,514     $   2,078,823
     Electric Services                                           427,662          414,868         1,132,647         1,084,309
     Energy Services                                             148,876          217,104           495,269           687,975
     Gas Exploration and Production                              123,052           88,600           373,774           256,089
     Energy Investments                                           26,447           23,599            80,287            62,784
                                                         ---------------------------------------------------------------------
Total Revenues                                                 1,131,814        1,078,202         5,052,491         4,169,980
                                                         ---------------------------------------------------------------------
Operating Expenses
     Purchased gas for resale                                    173,116          134,853         1,793,581         1,034,153
     Fuel and purchased power                                    132,649          144,259           332,647           326,327
     Operations and maintenance                                  507,381          487,293         1,515,206         1,538,073
     Depreciation, depletion and amortization                    135,656          127,301           422,917           380,758
     Operating taxes                                              91,790           89,103           311,754           282,663
                                                         ---------------------------------------------------------------------
Total Operating Expenses                                       1,040,592          982,809         4,376,105         3,561,974
                                                         ---------------------------------------------------------------------
Income from Equity Investments                                     2,727            2,299            12,486             9,713
Operating Income                                                  93,949           97,692           688,872           617,719
                                                         ---------------------------------------------------------------------
Other Income and (Deductions)
     Interest charges                                            (78,366)         (79,937)         (226,503)         (222,594)
     Loss on sale of subsidiary stock                                  -                -           (11,325)                -
     Cost of debt redemption                                           -                -           (24,094)                -
     Minority interest                                           (19,894)          (5,353)          (50,252)          (15,920)
     Other                                                        24,299           (3,549)           38,754            15,143
                                                         ---------------------------------------------------------------------
Total Other Income and (Deductions)                              (73,961)         (88,839)         (273,420)         (223,371)
                                                         ---------------------------------------------------------------------
Earnings Before Income Taxes                                      19,988            8,853           415,452           394,348
Income Taxes
     Current                                                     (39,317)         (34,508)           94,275           (97,430)
     Deferred                                                     46,720           38,397            71,439           243,011
                                                         ---------------------------------------------------------------------
Total Income Taxes                                                 7,403            3,889           165,714           145,581
                                                         ---------------------------------------------------------------------
Earnings from Continuing Operations                               12,585            4,964           249,738           248,767
                                                         ---------------------------------------------------------------------
Discontinued Operations
    Income from Operations, net of tax                                 -                -                 -                 -
    Loss on Disposal , net of tax of $13,050                           -                -                 -           (19,662)
                                                         ---------------------------------------------------------------------
Loss from Discontinued Operations                                      -                -                 -           (19,662)
                                                         ---------------------------------------------------------------------
Cummulative Effect of Change in Accounting Principle                   -                -               174                 -
                                                         ---------------------------------------------------------------------

Net Income                                                        12,585            4,964           249,912           229,105
Preferred stock dividend requirements                              1,461            1,335             4,383             4,287
                                                         ---------------------------------------------------------------------
Earnings  for Common Stock                                 $      11,124     $      3,629    $      245,529     $     224,818
                                                         =====================================================================
Basic Earnings Per Share From:
  Continuing Operations, less preferred dividends          $        0.07     $       0.03    $         1.56     $        1.74
  Discontinued Operations                                              -                -                 -             (0.14)
  Change in Accounting Principle                                       -                -                 -                 -
                                                         ---------------------------------------------------------------------
Basic Earnings Per Share                                   $        0.07     $       0.03    $         1.56     $        1.60
                                                         =====================================================================
Diluted Earnings Per Share From:
  Continuing Operations, less preferred dividends          $        0.07           $ 0.02    $         1.55     $        1.72
  Discontinued Operations                                              -                -                 -             (0.14)
  Change in Accounting Principle                                       -                -                 -                 -
                                                         ---------------------------------------------------------------------
Diluted Earnings Per Share                                 $        0.07     $       0.02    $         1.55     $        1.58
                                                         =====================================================================
Average Common Shares Outstanding (000)                          158,783          141,686           157,871           140,929
Average Common Shares Outstanding - Diluted (000)                159,539          142,359           158,670           141,760
------------------------------------------------------------------------------------------------------------------------------
</TABLE>

See accompanying Notes to the Consolidated Financial Statements.


                                       5
<PAGE>
<TABLE>
<CAPTION>
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                                   (Unaudited)

------------------------------------------------------------------------------------------
                                                            Nine Months Ended September 30,
(In Thousands of Dollars)                                         2003             2002
------------------------------------------------------------------------------------------
Operating Activities
<S>                                                             <C>             <C>
Net income                                               $        249,912    $    229,105
Adjustments to reconcile net income to net
      cash provided by (used in) operating activities
    Depreciation, depletion and amortization                      422,917         380,758
    Deferred income tax                                            71,439          60,495
    Income from equity investments                                (12,486)         (9,713)
    Dividends from equity investments                               1,021           1,777
    Amortization of interest rate swap                             (7,396)              -
    Loss on disposal of subsidiary investments                     11,325               -
    Gain on sale of property                                      (13,974)              -
    Minority interest in income of subsidiaries                    50,252          15,920
Changes in assets and liabilities
    Accounts receivable                                           384,836         239,569
    Materials and supplies, fuel oil and gas in storage          (239,847)         18,297
    Accounts payable and other liabilities                       (110,866)       (170,526)
    Interest accrued                                               22,161          20,573
    Pension/OPEB funding                                         (125,385)        (40,294)
    Other                                                          33,154           9,360
                                                       -----------------------------------
Net Cash Provided by Operating Activities                         737,063         755,321
                                                       -----------------------------------
Investing Activities
    Construction expenditures                                    (720,217)       (815,155)
    Other investment                                              (50,500)              -
    Proceeds from sale of property                                 13,974               -
    Proceeds from sale of subsidiary investments                  198,553         173,935
                                                       -----------------------------------
Net Cash Used in Investing Activities                            (558,190)       (641,220)
                                                       -----------------------------------
Financing Activities
    Treasury stock issued                                          76,984          67,308
    Equity issuance                                               473,573               -
    Issuance of long-term debt                                    710,475         515,774
    Payment of long-term debt                                    (564,506)        (91,152)
    Payment of commercial paper                                  (271,297)       (519,222)
    Redemption of promissory notes                               (447,005)              -
    Redemption of preferred stock                                 (14,293)              -
    Preferred stock dividends paid                                 (4,383)         (4,287)
    Common stock dividends paid                                  (203,795)       (187,857)
    Other                                                          12,808               9
                                                       -----------------------------------
Net Cash Used in Financing Activities                            (231,439)       (219,427)
                                                       -----------------------------------
Net Increase in Cash and Cash Equivalents                $        (52,566)   $   (105,326)
Cash and Cash Equivalents at Beginning of Period                  170,617         159,252
                                                       -----------------------------------
Cash and Cash Equivalents at End of Period               $        118,051    $     53,926
                                                       ===================================
------------------------------------------------------------------------------------------
</TABLE>

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

        See accompanying Notes to the Consolidated Financial Statements.


                                       6
<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

1. BASIS OF PRESENTATION

In our opinion,  the accompanying  unaudited  Consolidated  Financial Statements
contain all adjustments necessary to present fairly KeySpan's financial position
as of September 30, 2003,  and the results of operations  for the three and nine
months ended  September  30, 2003 and  September 30, 2002, as well as cash flows
for the nine  months  ended  September  30, 2003 and  September  30,  2002.  The
accompanying  financial  statements  should  be read  in  conjunction  with  the
consolidated  financial statements and notes included in KeySpan's Annual Report
on Form 10-K for the year ended December 31, 2002, as well as KeySpan's March 31
and June 30,  2003  Quarterly  Reports  on Form  10-Q.  The  December  31,  2002
financial statement information has been derived from the 2002 audited financial
statements. Income from interim periods may not be indicative of future results.
Certain reclassifications were made to conform prior period financial statements
to current period financial statement presentation.

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

We have  approximately  2 million common stock options  outstanding at September
30,  2003 that were not  included  in the  calculation  of diluted EPS since the
exercise price associated with these options was greater than the average market
price of our  common  stock.  Further,  we have  88,486  shares  of  convertible
preferred stock  outstanding that can be converted into 228,406 shares of common
stock.  These shares were not included in the calculation of diluted EPS for the
three and nine months  ended  September  30, 2003 since to do so would have been
anti-dilutive.


                                       7
<PAGE>

Under the requirements of Statement of Financial  Accounting  Standards ("SFAS")
No. 128, "Earnings Per Share," our basic and diluted EPS are as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                                                            Three Months Ended September 30,   Nine Months Ended September 30,
(In Thousands of Dollars, Except Per Share Amounts)                2003              2002           2003             2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>            <C>           <C>                <C>
Earnings for common stock                                        $   11,124       $   3,629     $ 245,529           $ 224,818
Houston Exploration dilution                                            (74)            (96)         (212)               (321)
------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted                             $   11,050       $   3,533     $ 245,317           $ 224,497
------------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000)                           158,783         141,686       157,871             140,929
Add dilutive securities:
Options                                                                 756             673           799                 831
------------------------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution       159,539         142,359       158,670             141,760
------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share                                         $     0.07       $    0.03     $    1.56           $    1.60
------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share                                       $     0.07       $    0.02     $    1.55           $    1.58
------------------------------------------------------------------------------------------------------------------------------
</TABLE>


2. BUSINESS SEGMENTS

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

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

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


                                       8
<PAGE>

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

During the third quarter of 2003,  KeySpan  Services,  Inc. and its wholly-owned
subsidiary  Paulus,  Sokolowski,  and Sartor,  LLC. acquired Bard, Rao + Athanas
Consulting Engineers, LLC. ("BR+A"), a Boston,  Massachusetts company engaged in
the business of providing engineering services relating to heating, ventilation,
and air conditioning  systems. The purchase price was approximately $35 million,
plus up to $14.7 million in contingent  consideration depending on the financial
performance  of BR+A over the  five-year  period  following  the  closing of the
acquisition.  We have recorded  goodwill of $26 million and intangible assets of
$2 million associated with this transaction. The intangible assets, which relate
primarily  to a portion  of the  backlog  purchased,  as well as to  non-compete
agreements entered into with all of the former owners of BR+A, will be amortized
over two and three  years,  respectively.  We are  currently  in the  process of
evaluating  the fair  market  value of the  assets  acquired  and may adjust the
recorded  goodwill and  intangible  assets in the fourth quarter of 2003. In May
2003, KeySpan's gas and electric marketing  subsidiary,  KeySpan Energy Services
Inc.,  assigned the  majority of its retail  natural gas  customers,  consisting
mostly of residential and small commercial  customers,  to ECONnergy Energy Co.,
Inc.  ("ECONnergy").  KeySpan  Energy  Services will continue to provide  retail
natural gas  marketing to a small number of customers in New Jersey and plans to
continue its electric marketing activities.

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


                                       9
<PAGE>

On October 15,  2003,  Houston  Exploration  acquired  the entire Gulf of Mexico
shallow-water asset base of Transworld Exploration and Production,  Inc for $149
million.  The properties,  which are 75% natural gas, have proven reserves of 92
billion  cubic feet of natural gas  equivalent.  Current  production  is from 11
fields  and is  producing  approximately  35 million  cubic feet of natural  gas
equivalent per day.  Houston  Exploration  funded the transaction  from its bank
revolver  and with  cash on hand at the time of  closing.  Consistent  with past
acquisitions,  Houston Exploration has derivative hedge positions in place for a
portion of the 2004 production.

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. These subsidiaries are accounted for under the equity method.

We also have  investments  in certain  midstream  natural  gas assets in Western
Canada through  KeySpan  Canada.  These assets include 14 processing  plants and
associated gathering systems that can process  approximately 1.5 BCFe of natural
gas daily and provide associated natural gas liquids fractionation. In May 2003,
we sold a portion of our interest in KeySpan Canada through the establishment of
an open-ended income fund trust ("KeySpan Facilities Income Fund" or the "Fund")
organized  under  the  laws of  Alberta,  Canada.  The  Fund  acquired  a 39.09%
ownership  interest in KeySpan Canada through an indirect  subsidiary,  and then
issued 17 million trust units to the public through an initial public  offering.
Each trust unit  represents a beneficial  interest in the Fund and is registered
on the Toronto Stock Exchange under the symbol KEY.UN. Additionally, we sold our
20% interest in Taylor NGL LP that owns and operates two extraction  plants also
in Canada to AltaGas Services,  Inc. Net proceeds of $119.4 million from the two
sales,  plus proceeds of $45.7  million  drawn under a new credit  facility made
available  to KeySpan  Canada,  were used to pay down  existing  KeySpan  Canada
credit  facilities  of $160.4  million.  A  pre-tax  loss of $30.3  million  was
recognized on the  transactions and is included in Other Income and (Deductions)
in the  Consolidated  Statement  of Income.  These  transactions  produced a tax
expense of $3.8 million as a result of certain  United  States  partnership  tax
rules and we, therefore, recorded an after-tax loss of $34.1 million.

The  accounting  policies  of the  segments  are the same as those  used for the
preparation of the Consolidated Financial Statements. The segments are strategic
business units that are managed separately because of their different  operating
and regulatory environments.  Operating results of our segments are evaluated by
management on an operating income basis. Except as noted above, at September 30,
2003, the total assets of each  reportable  segment have not changed  materially
from those  levels  reported  at  December  31,  2002.  The  reportable  segment
information is as follows:



                                       10
<PAGE>

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                                                              Energy Investments
                                                                        -----------------------------
                                         Gas        Electric  Energy     Gas Exploration  Other
(InThousands of Dollars)             Distribution   Services  Services   and Production   Investments  Eliminations   Consolidated
----------------------------------------------------------------------------------------------------------------------------------
<S>                                    <C>         <C>       <C>           <C>            <C>           <C>           <C>
Three Months Ended Sept. 30, 2003
Unaffiliated revenue                    405,777     427,662   148,876       123,052        26,447              -       1,131,814
Intersegment revenue                          -          25     1,926             -         1,252         (3,203)              -
Operating Income (Loss)                 (39,108)    100,254   (13,627)       50,995         8,009        (12,574)         93,949

Three Months Ended Sept. 30, 2002
Unaffiliated revenue                    334,031     414,868   217,104        88,600        23,599              -       1,078,202
Intersegment revenue                          -          25         -             -           194           (219)              -
Operating Income (Loss)                 (39,565)    106,611    (4,834)       26,354        10,526         (1,400)         97,692
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

Because of the nature of our Electric Services  business,  electric revenues are
derived  from two  large  customers  - the NYISO  and  LIPA.  Electric  Services
revenues from these  customers for the three months ended September 30, 2003 and
2002 represent approximately 38% of our consolidated revenues for both periods.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                Energy Investments
                                                                         -------------------------------
                                         Gas        Electric    Energy    Gas Exploration      Other
(InThousands of Dollars)            Distribution    Services   Services   and Production     Investments Eliminations  Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>           <C>         <C>         <C>              <C>          <C>            <C>
Nine Months Ended Sept. 30, 2003
Unaffiliated revenue                  2,970,514     1,132,647   495,269     373,774           80,287            -        5,052,491
Intersegment revenue                          -            76     4,894           -            3,756       (8,726)               -
Operating Income (Loss)                 357,445       191,404   (32,647)    156,733           27,207      (11,270)         688,872

Nine Months Ended Sept. 30, 2002
Unaffiliated revenue                  2,078,823     1,084,309   687,975     256,089           62,784            -        4,169,980
Intersegment revenue                          -            75         -           -              582         (657)               -
Operating Income (Loss)                 321,551       227,613   (25,056)     75,633           15,081        2,897          617,719

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

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

Because of the nature of our Electric Services  business,  electric revenues are
derived  from two  large  customers  - the NYISO  and  LIPA.  Electric  Services
revenues from these  customers for the nine months ended  September 30, 2003 and
2002  represent   approximately  22%  and  26%  of  our  consolidated  revenues,
respectively.


                                       11
<PAGE>


3. COMPREHENSIVE INCOME

The table below indicates the components of comprehensive income.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                       Three Months Ended Sept. 30,      Nine Months Ended Sept. 30,
(In Thousands of Dollars)                                                2003             2002            2003              2002
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>             <C>             <C>               <C>
Earnings for common stock                                              $ 11,124        $   3,629       $ 245,529         $ 224,818
-----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
Reclassification adjustments for loss (gains) realized in net income      8,431           (7,529)         19,602           (17,814)
Foreign currency translation adjustments                                    366           (2,313)         27,892             6,804
Unrealized gains (losses) on marketable securities                        1,209           (4,027)          3,458            (8,263)
Accrued unfunded pension obligation                                           -                -               -            (1,132)
Premiums on derivative financial instruments                                  -                -          (3,437)                -
Unrealized gains (losses) on derivative financial instruments            13,740             (641)         (7,193)          (26,585)
-----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax                            23,746          (14,510)         40,322           (46,990)
-----------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income (Loss)                                            $ 34,870        $ (10,881)      $ 285,851         $ 177,828
-----------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Reclassification adjustments for loss (gains) realized in net income   $  4,540        $  (4,054)      $  10,555         $  (9,592)
Foreign currency translation adjustments                                    197           (1,245)         15,019             3,663
Unrealized gains (losses) on marketable securities                          652           (2,168)          1,863            (4,449)
Accrued unfunded pension obligation                                           -                -               -              (610)
Premiums on derivative financial instruments                                  -                -          (1,851)                -
Unrealized gains (losses) on derivative financial instruments             7,398             (346)         (3,873)          (14,316)
-----------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense                                            $ 12,787        $  (7,813)      $  21,713         $ (25,304)
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


4. CAPITAL AND PREFERRED STOCK

In September  2003,  the Boston Gas Company  redeemed all 562,700  shares of its
outstanding Variable Term Cumulative Preferred Stock, 6.42 % Series A at its par
value of $25 per share.  The total payment was $14.3 million which included $0.2
million of accumulated dividends. This preferred stock series had been reflected
as Minority Interest on KeySpan's Consolidated Balance Sheet.

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

5. LONG-TERM DEBT AND COMMERCIAL PAPER

During the third quarter of 2003,  KeySpan Canada,  issued Cdn$125  million,  or
approximately  US$93 million,  long-term secured notes in a private placement to
investors  in  Canada  and the  United  States.  The  notes  were  issued in the
following three series:  (i) Cdn$20 million 5.42% senior secured notes due 2008;
(ii) Cdn$52.5  million 5.79% senior  secured notes due 2010;  and (iii) Cdn$52.5
million 6.16% senior  secured notes due 2013.  The proceeds of the offering have
been used to re-pay KeySpan Canada's credit facility.


                                       12
<PAGE>


In June 2003, as part of the sale of a portion of KeySpan's ownership in KeySpan
Canada, two outstanding  KeySpan Canada credit facilities were replaced with one
new facility with three tranches that combined  allowed KeySpan Canada to borrow
up to  approximately  $125  million.  As a result  of the above  long-term  debt
issuance,  one tranch of the credit  facility was  discontinued.  Therefore,  at
September  30, 2003,  KeySpan  Canada's  credit  facility has the  following two
tranches with the following  maturities:  (i) $37.5 million matures in 364 days;
and (ii) $37.5 million matures in two years.

In June 2003, KeySpan renewed its $1.3 billion revolving credit facility,  which
was  syndicated  among sixteen banks.  The credit  facility  supports  KeySpan's
commercial  paper program,  and consists of two separate credit  facilities with
different  maturities but  substantially  similar terms and  conditions:  a $450
million  facility that extends for 364 days, and a $850 million facility that is
committed  for  three  years.  The  fees for the  facilities  are  subject  to a
ratings-based  grid,  with an annual fee that  ranges  from eight to twenty five
basis  points on the  364-day  facility  and ten to thirty  basis  points on the
three-year  facility.  Both credit  agreements allow for KeySpan to borrow using
several different types of loans;  specifically,  Eurodollar  loans,  Adjustable
Bank Rate (ABR) loans, or competitively bid loans. Eurodollar loans are based on
the  Eurodollar  rate plus a margin.  ABR loans are based on the  highest of the
Prime Rate,  the base CD rate plus 1%, or the Federal Funds  Effective Rate plus
0.5%, plus a margin. Competitive bid loans are based on bid results requested by
KeySpan from the lenders.  The margins on both  facilities are ratings based and
range from zero basis points to 112.5 basis points. The margins are increased if
outstanding loans are in excess of 33% of the total facility.  In addition,  the
364-day facility has a one-year term out option,  which would cost an additional
0.25%  if  utilized.  We do not  anticipate  borrowing  against  this  facility;
however,  if the  credit  rating  on our  commercial  paper  program  were to be
downgraded, it may be necessary to do so.

On June 10, 2003, Houston Exploration  finalized a private placement issuance of
$175 million of 7.0%, senior subordinated notes due 2013. Interest payments will
begin on December 15, 2003, and will be paid semi-annually thereafter. The notes
will mature on June 15, 2013.  Houston  Exploration  has the right to redeem the
notes as of June 15, 2008,  at a price equal to the issue price plus a specified
redemption premium.  Until June 15, 2006, Houston Exploration may also redeem up
to 35% of the notes at a redemption  price of 107% with  proceeds from an equity
offering.  Houston  Exploration  incurred  approximately  $4.5  million  of debt
issuance costs on this private placement.

Houston  Exploration  used a portion of the net  proceeds  from the  issuance to
redeem all of its  outstanding  $100 million  principal  amount of 8.625% senior
subordinated  notes due 2008 at a price of 104.313% of par plus interest accrued
to the redemption date. Debt redemption costs totaled approximately $5.9 million
and is reflected in Other Income and (Deductions) in the Consolidated  Statement
of Income. The remaining net proceeds from the offering were used to reduce debt
amounts associated with Houston Exploration's bank revolving credit facility.


                                       13
<PAGE>

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

In connection with the KeySpan/Long  Island Lighting Company ("LILCO")  business
combination in 1998,  KeySpan and certain of its subsidiaries  issued promissory
notes to LIPA to support certain debt  obligations  assumed by LIPA. At December
31, 2002, the remaining  principal amount of promissory notes issued to LIPA was
approximately  $600  million.  To  mitigate  the  dilutive  effect of the equity
issuance previously  mentioned in Note 4, in March 2003 we called  approximately
$447  million  aggregate  principal  amount  of  such  promissory  notes  at the
applicable  redemption prices plus accrued and unpaid interest through the dates
of redemption. Interest savings associated with this redemption are estimated to
be $15.6  million  after-tax,  or $0.09  per  share,  in 2003.  We  applied  the
provisions  of  Statement  of  Financial   Accounting   Standards  ("SFAS")  145
"Rescission of FASB Statement No. 4, 44 and 64,  Amendment of FASB Statement No.
13, and  Technical  Corrections"  and  recorded  an  expense  of $18.2  million,
reflecting  redemption  costs,  as well as the write-off of previously  deferred
debt  issuance  costs.  This  expense  has been  recorded  in Other  Income  and
Deductions in the Consolidated Statement of Income.

KeySpan has authorization  under PUHCA to issue up to $2.2 billion of securities
through December 31, 2003. Following the recent common stock offering previously
mentioned and shares of common stock expected to be issued for employee  benefit
and dividend  reinvestment  plans, we have nearly exhausted our ability to issue
new securities under our current PUHCA  authorization.  However, the issuance of
securities in connection with the redemption of existing  securities  (including
the  promissory  notes  discussed  previously)  is  permitted  under  our  PUHCA
authorization  notwithstanding the foregoing limit. We have filed an application
with the SEC  requesting  authorization  to, among other things,  issue up to an
additional $3 billion of securities through December 31, 2006. It is anticipated
that this  authorization  will be  obtained  before  the end of the  year.  This
request is intended to provide us with maximum flexibility to finance our future
capital requirements over the next three years.

6. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

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

Houston  Exploration has utilized collars and purchased put options,  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
September 30, 2003, Houston Exploration has hedged slightly less than 70% of its
estimated 2003 gas  production and a similar amount of its 2004 gas  production.
Houston Exploration used standard New York Mercantile Exchange ("NYMEX") futures
prices to value its swap positions,  and, in addition, used published volatility
in its Black-Scholes  calculation for outstanding options. The maximum length of
time over  which  Houston  Exploration  has  hedged  such  cash flow is  through
December 2004. The estimated  amount of losses  associated  with such derivative
instruments  that  are  reported  in  Other  Comprehensive  Income  and that are
expected to be  reclassified  into earnings over the next twelve months is $10.5
million, or $6.8 million after-tax.


                                       14
<PAGE>

With respect to price exposure associated with fuel purchases for the Ravenswood
facility,  KeySpan  employs  standard  NYMEX  natural gas futures  contracts and
over-the-counter  financially  settled natural gas basis swaps to hedge the cash
flow  variability for a portion of forecasted  purchases of natural gas. KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow variability for a portion of forecasted  purchases of fuel oil that will be
consumed at the  Ravenswood  facility.  The maximum length of time over which we
have  hedged cash flow  variability  associated  with  forecasted  purchases  of
natural  gas and fuel oil is through  September  2005.  We used  standard  NYMEX
futures  prices to value the gas futures  contracts  and industry  published oil
indices  for  number  6 grade  fuel oil to value  the oil  swap  contracts.  The
estimated amount of gains  associated with all such derivative  instruments that
are  reported  in  Other  Comprehensive  Income  and  that  are  expected  to be
reclassified into earnings over the next twelve months is $0.2 million,  or $0.1
million after-tax.

KeySpan Canada employs  natural gas swaps to lock-in a price for expected future
natural gas purchases.  As applicable,  we used 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 or losses associated with such derivative instruments that are reported
in Other  Comprehensive  Income and that are  expected to be  reclassified  into
earnings over the next twelve months is negligible at September 30, 2003.

We have also engaged in the use of  cash-settled  swap  instruments to hedge the
cash flow  variability  associated  with a portion of  forecasted  peak electric
energy  sales  from the  Ravenswood  facility,  as well as  forecasted  sales of
Unforced  Capacity  ("UCAP") to the NYISO. The maximum length of time over which
we have hedged cash flow  variability  is through  December  2004. We used NYMEX
day-ahead forward pricing,  as well as published NYISO day-ahead award prices to
value these outstanding  derivatives.  The estimated amount of losses associated
with such derivative instruments that are reported in Other Comprehensive Income
and that are  expected to be  reclassified  into  earnings  over the next twelve
months is $1.3 million, or $0.8 million after-tax.

KeySpan Canada also employs  electricity  swap contracts to lock-in the purchase
price  of  electricity  needed  to  operate  its gas  processing  plants.  These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $0.4 million, or $0.3 million after-tax.


                                       15
<PAGE>

<TABLE>
The following  tables set forth selected  financial data  associated  with these
derivative financial  instruments noted above that were outstanding at September
30, 2003.
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                                   Year of    Volumes       Floor          Ceiling      Fixed Price      Current Price    Fair Value
          Type of Contract        Maturity    (mmcf)        ($)             ($)            ($)              ($)            ($000)
-----------------------------------------------------------------------------------------------------------------------------------
                Gas
<S>                                 <C>       <C>       <C>             <C>            <C>              <C>                <C>
Collars                              2003      13,800           3.48            4.91              -      4.43 - 5.08        (4,085)
                                     2004      64,100    3.50 - 4.50     4.75 - 7.00              -      4.70 - 5.26        (7,757)

Put Options - Short Natural Gas      2004       9,100           5.00               -              -      5.11 - 5.26         4,228

Swaps/Futures - Short Natural Gas    2003       3,711              -               -           3.19      4.43 - 5.08        (5,842)
                                     2004      14,640              -               -           4.96      4.76 - 5.26         1,152

Swaps/Futures - Long Natural Gas     2004          50              -               -    5.11 - 5.14      4.71 - 4.72           (25)
                                     2005          10              -               -           4.95             4.46            (5)

-----------------------------------------------------------------------------------------------------------------------------------
                                              105,411                                                                      (12,334)
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------
                                Year of        Volumes         Fixed Price         Current Price        Fair Value
        Type of Contract        Maturity      (Barrels)            ($)                  ($)               ($000)
-----------------------------------------------------------------------------------------------------------------
             Oil
<S>                              <C>          <C>            <C>                  <C>                      <C>
Swaps - Long Fuel Oil             2003          55,367        20.60 - 30.07        28.54 - 29.80             204
                                  2004         100,548        20.55 - 29.60        25.88 - 28.61              37
                                  2005          28,000        24.65 - 27.25        25.25 - 25.59             (31)
-----------------------------------------------------------------------------------------------------------------
                                               183,915                                                       210
-----------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                               Year of                                     Fixed Price       Current Price          Fair Value
        Type of Contract       Maturity        Capacity         MWh             ($)                ($)                 ($000)
------------------------------------------------------------------------------------------------------------------------------
          Electricity
<S>                             <C>             <C>           <C>         <C>                <C>                      <C>
Swaps - Energy                   2003                          222,464     15.00 - 67.44      15.90 - 42.98              (613)
                                 2004                          340,800     14.00 - 26.50      17.15 - 41.96              (953)

Swaps - Capacity                 2003             100                -              7.00               6.98                 2
                                 2004             200                -              7.00               6.98                 4


------------------------------------------------------------------------------------------------------------------------------
                                                  300          563,264                                                 (1,560)
------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       16
<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 swap  transactions  for  natural gas  liquids.  Such  contracts  are
executed  by KeySpan  Canada to: (i) 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 to  counterparties.
These derivative financial instruments do not qualify for hedge accounting under
SFAS 133,  "Accounting for Derivative  Instruments  and Hedging  Activities." At
September  30,  2003,  these  instruments  had a net fair  market  value of $1.3
million,  which was recorded on the  Consolidated  Balance  Sheet.  Based on the
non-hedge  designation  of these  instruments,  the gain was  recognized  in the
Consolidated Statement of Income.

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

The following  table sets forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at September 30, 2003.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                          Year of       Volumes      Floor          Ceiling        Fixed Price       Current Price      Fair Value
   Type of Contract      Maturity         mmcf        ($)              ($)             ($)               ($)               ($000)
----------------------------------------------------------------------------------------------------------------------------------
<S>                      <C>            <C>      <C>              <C>             <C>                <C>                 <C>
Options                   2003            2,650   4.00 - 5.00      5.15 - 6.00               -        4.90 - 5.13            (712)
                          2004            7,420   4.00 - 5.00      5.15 - 6.00               -        4.83 - 5.25            (411)

Swaps                     2003           10,710             -                -     5.00 - 6.23        4.90 - 5.13          (5,304)
                          2004           20,530             -                -     4.42 - 6.23        4.83 - 5.25          (6,848)
----------------------------------------------------------------------------------------------------------------------------------
                                         41,310                                                                           (13,275)
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


Physically-Settled  Commodity Derivative Instruments:  Derivative Implementation
Group ("DIG") Issue C15 and C16 of SFAS 133, as amended and interpreted,  ("SFAS
133")  establishes  criteria that must be satisfied in order for option-type and
forward  contracts in electricity to be exempted as normal  purchases and sales,
and relates to the exemption (as normal purchases and normal sales) of contracts


                                       17
<PAGE>

that combine a forward contract and a purchased  option  contract.  Based upon a
continuing  review of our  physical  gas and electric  commodity  contracts,  we
determined  that  certain  contracts  for the  physical  purchase of natural gas
associated  with our regulated gas utilities are not exempt as normal  purchases
from the  requirements  of SFAS 133. At September  30,  2003,  the fair value of
these contracts was $2.8 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: In May 2003, we entered into interest rate
swap  agreements  in which we swapped  $250 million of 7.25 % fixed rate debt to
floating rate debt. Under the terms of the agreements, we will receive the fixed
coupon  rate  associated  with  these  bonds and pay our swap  counterparties  a
variable  interest rate based on LIBOR,  that is reset on a  semi-annual  basis.
These swaps are  designated  as  fair-value  hedges and qualify for  "short-cut"
hedge accounting treatment under SFAS 133. During the period ended September 30,
2003, we paid our  counterparty an interest rate of 6.42%,  and as a result,  we
realized  interest  savings  of $0.4  million.  The  fair  market  value of this
derivative was $1.4 million at September 30, 2003.

During  2002,  we  had  interest  rate  swap  agreements  in  which  we  swapped
approximately  $1.3 billion of fixed rate debt to floating rate debt.  Under the
terms of the agreements, we received the fixed coupon rate associated with these
bonds and paid the swap  counterparties a variable  interest rate that was reset
on a quarterly  basis.  These swaps were  designated  as  fair-value  hedges and
qualified for "short-cut" hedge accounting treatment under SFAS 133. In 2002, we
terminated two of these interest rate swap agreements with an aggregate notional
amount of $1.0  billion.  The  remaining  swap,  which had a notional  amount of
$270.0  million,  was terminated on February 25, 2003. We received $18.4 million
from our swap  counterparties  as a result of the latter  termination,  of which
$8.1 million  represented  accrued swap  interest.  The  difference  between the
termination settlement amount and the amount of accrued interest, $10.3 million,
was  recorded to earnings  in the first  quarter of 2003.  This swap was used to
hedge a portion of our  outstanding  promissory  notes to LIPA.  As discussed in
Note 5 "Long-Term  Debt," we called a portion of these  promissory  notes during
the first quarter of 2003.

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

Weather  Derivatives:  The utility tariffs associated with KEDNE's operations do
not contain weather normalization  adjustments.  As a result,  fluctuations from
normal weather may have a significant positive or negative effect on the results
of these  operations.  To  mitigate  a  substantial  portion  of the  effect  of
fluctuations  from normal weather on our financial  position and cash flows,  we
sold  heating  degree-day  call  options and  purchased  heating-degree  day put
options for the November  2002-March  2003 winter  season.  With respect to sold
call  options,  KeySpan  was  required  to make a payment of $40,000 per heating
degree day to its  counterparties  when actual  weather  experienced  during the
November 2002 - March 2003 time frame was above 4,470 heating degree days, which
equates  to  approximately  1% colder  than  normal  weather.  With  respect  to


                                       18
<PAGE>

purchased put options,  KeySpan would have received a $20,000 per heating degree
day payment from its counterparties  when actual weather was below 4,150 heating
degree days, or approximately 7% warmer than normal.  Based on the terms of such
contracts,  we account for such instruments pursuant to the requirements of EITF
99-2,  "Accounting for Weather  Derivatives."  In this regard,  such instruments
were  accounted  for using the  "intrinsic  value  method"  as set forth in such
guidance.  During the first quarter of 2003,  weather was 10% colder than normal
and, as a result, $11.9 million has been recorded as a reduction to revenues.

In October  2003,  we entered  into  heating-degree  day call and put options to
mitigate the effect of  fluctuations  from normal  weather on KEDNE's  financial
position and cash flows for the 2003/2004  winter heating season - November 2003
through March 2004. With respect to sold call options,  KeySpan will be required
to make a payment of $27,500 per heating degree day to its  counterparties  when
actual weather  experienced during this time frame is above 4,440 heating degree
days, which equates to approximately 2% colder than normal weather, based on the
most recent 20-year average for normal  weather.  The maximum amount KeySpan may
be required to pay on its sold call  options is $5.5  million.  With  respect to
purchased  put options,  KeySpan  will receive a $27,500 per heating  degree day
payment  from its  counterparties  when actual  weather is below  4,266  heating
degree days, or approximately 2% warmer than normal.  The maximum amount KeySpan
may receive on its purchased put options is $11 million.  The total premium cost
for these  options  was $0.4  million.  We will  account  for these  derivatives
pursuant to the requirements of EITF 99-2.

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

7. RECENT ACCOUNTING PRONOUNCEMENTS

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

At  September  30,  2003,  the  present  value of our  future  asset  retirement
obligation  ("ARO") was  approximately  $65  million,  primarily  related to our
investment in Houston  Exploration.  The  cumulative  effect of SFAS 143 and the
change in  accounting  principle  was a benefit to net  income of $0.2  million,
after-tax. KeySpan's largest asset base is its gas transmission and distribution
system.  A legal obligation  exists due to certain safety  requirements at final
abandonment.  In  addition,  a legal  obligation  may be construed to exist with
respect to KeySpan's liquefied natural gas ("LNG") storage tanks due to clean up
responsibilities  upon cessation of use.  However,  mass assets such as storage,


                                       19
<PAGE>

transmission and distribution  assets are believed to operate in perpetuity and,
therefore,  have  indeterminate  cash flow estimates.  Since that exposure is in
perpetuity  and cannot be measured,  no liability  will be recorded  pursuant to
SFAS 143.  KeySpan's ARO will be re-evaluated in future periods until sufficient
information exists to determine a reasonable estimate of fair value.

KeySpan  recovers  certain  asset  retirement  costs  through  rates  charged to
customers as a portion of depreciation expense. When depreciable  properties are
retired,  the  original  cost plus cost of removal less  salvage,  is charged to
accumulated depreciation.  As of September 30, 2003, KeySpan had costs recovered
in excess of costs incurred totaling $458 million.

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

In April  2003,  the FASB  issued  SFAS  149,  "Amendment  of  Statement  133 on
Derivative  Instruments  and  Hedging  Activities".  This  Statement  amends and
clarifies  financial  accounting  and  reporting  for  derivative   instruments,
including  certain  instruments  embedded  in other  contracts  and for  hedging
activities under Statement No. 133,  "Accounting for Derivative  Instruments and
Hedging  Activities." This Statement:  (i) clarifies under what  circumstances a
contract  with  an  initial  net  investment  meets  the   characteristic  of  a
derivative;  (ii)  clarifies when a derivative  contains a financing  component;
(iii) amends the  definition  of an  underlying;  and (iv) amends  certain other
existing  pronouncements.  The  implementation of this Statement will not have a
significant  impact on our results of  operations,  financial  condition or cash
flows since our derivative  instruments that meet the definition of a derivative
and qualify for hedge accounting treatment will continue to do so.

In May  2003,  the FASB  issued  SFAS 150,  "Accounting  for  Certain  Financial
Instruments with Characteristics of Both Liabilities and Equity." This Statement
establishes  standards  for  how  an  issuer  classifies  and  measures  certain
financial  instruments with  characteristics  of both liabilities and equity. It
requires that an issuer classify  certain  financial  instruments as a liability
(or an asset in some  circumstances)  when there is an  obligation to redeem the
issuer's  shares  and  either  requires  or  may  require  satisfaction  of  the
obligation  by  transferring  assets,  or  satisfy  the  obligation  by  issuing
additional  equity  shares  subject  to  certain  criteria.  This  Statement  is
effective for financial instruments entered into or modified after May 31, 2003,
and  otherwise  is  effective  at the  beginning  of the  first  interim  period


                                       20
<PAGE>

beginning  after  June  15,  2003.  It is to be  implemented  by  reporting  the
cumulative  effect  of  a  change  in  an  accounting  principle  for  financial
instruments created before the issuance date of the Statement and still existing
at the beginning of the interim period of adoption.  The  implementation of this
Statement  did not  have an  impact  on our  results  of  operations,  financial
condition or cash flows.

In July 2003, the Financial  Accounting  Standards Board ("FASB")  concluded its
discussions on Emerging  Issues Task Force ("EITF")  03-11  "Reporting  Realized
Gains and Losses on Derivative  Instruments  That Are Subject to FASB  Statement
No. 133  Accounting for Derivative  Instruments  and Hedging  Activities and Not
Held for Trading  Purposes as Defined in EITF Issue No. 02-3 Issues  Involved in
Accounting  for  Derivative  Contracts  held for Trading  Purposes and Contracts
Involved  in Energy  Trading  and Risk  Management  Activities."  The Task Force
reached  a  consensus  that  determining  whether  realized  gains or  losses on
physically settled  derivative  contracts not "held for trading purposes" should
be  reported  in the  income  statement  on a gross or net  basis is a matter of
judgment that depends on the relevant facts and  circumstances.  KeySpan reports
realized gains or losses on its derivative  instruments that hedge the cash flow
variability  associated with the forecasted sales of natural gas and electricity
in its reported revenues at time of their  settlement.  Realized gains or losses
on derivative  instruments that hedge the cash flow variability  associated with
the  forecasted  purchase of natural gas or fuel oil are  reported in  operating
expense.  While we will continue to evaluate the  provisions  of EITF 03-11,  we
believe  that this EITF will not have a  significant  impact on our  results  of
operations, financial condition or cash flows.

8. FINANCIAL GUARANTEES AND CONTINGENCIES

Environmental Matters

New York Sites. We have  identified 28 manufactured  gas plant ("MGP") sites and
related facilities in New York State that were historically owned or operated by
KeySpan  subsidiaries  or such  companies'  predecessors.  Twenty seven of these
former sites, some of which are no longer owned by KeySpan, were associated with
the  regulated gas  businesses,  and have been  identified to the  Department of
Environmental Conservation ("DEC") for inclusion on appropriate site inventories
and for  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 $124.6  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 $67.2 million.  The KEDNY and
KEDLI rate plans generally provide for the recovery of MGP related investigation
and  remediation  costs as costs  are  incurred.  A  regulatory  asset of $142.6


                                       21
<PAGE>

million for the New  York/Long  Island MGP sites is reflected  at September  30,
2003. In accordance with NYPSC policy, KeySpan records a reduction to regulatory
liabilities  as costs are incurred for  environmental  clean-up  activities.  At
September 30, 2003, these previously  deferred  ratepayer benefits totaled $42.8
million.  In October 2003, KEDNY and KEDLI filed a joint petition with the NYPSC
seeking rate treatment for additional  environmental  costs that may be incurred
in the  future.  KeySpan  is  also  responsible  for  environmental  obligations
associated with the Ravenswood electric generating facility.  Our obligations do
not include those arising from disposal of waste at off-site  locations prior to
our acquisition of the Ravenswood  facility,  or any from Consolidated  Edison's
post-closing  conduct  associated with its transmission  facilities at the site.
Based on information  currently available,  a liability of $3.5 million has been
accrued.  Expenditures  incurred  to date with  respect  to these  environmental
obligations total $1.4 million.

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

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

We may have or share responsibility under applicable  environmental laws for the
remediation  of  10  MGP  sites  and  related  facilities  associated  with  the
historical   operations  of  EnergyNorth  Natural  Gas,  Inc.   ("EnergyNorth").
EnergyNorth   has  received   notice  of  its   potential   responsibility   for
contamination  at two  former  MGP sites and,  together  with other  potentially
responsible  parties,  has  received  notice  of  potential  responsibility  for
contamination associated with four other sites.

We presently  estimate  the  remaining  cost of all the New England  MGP-related
environmental  cleanup  activities will be $45.2 million,  which amount has been
accrued as a reasonable estimate of probable cost for known sites.  Expenditures
incurred since our  acquisition of Eastern  Enterprises on November 8, 2000 with
respect to these MGP-related activities total $18.8 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 $54.3
million for the KEDNE MGP sites is reflected at September 30, 2003. Colonial Gas
Company  and Essex Gas  Company  are not  subject to the  provisions  of 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.


                                       22
<PAGE>

KeySpan  New  England  LLC  Sites.  We are  aware  of  three  non-utility  sites
associated  with the  historical  operations  of KeySpan New  England,  LLC, the
successor  company  to  Eastern  Enterprises,  for  which  we may  have or share
environmental  remediation  responsibility  or ongoing  maintenance:  the former
Philadelphia Coke site located in Pennsylvania; the former Connecticut Coke site
located in New Haven,  Connecticut;  and the Everett  site,  which  includes the
former Coal Tar  Processing  Facility (the "Everett  Coal Tar  Facility"),  Coke
Plant  and  a  by-products   facility   located  in   Massachusetts.   Honeywell
International,  Inc. and Beazer East,  Inc.  (both former owners or operators of
the Everett Coal Tar  Facility)  together  with KeySpan have entered into an ACO
with  the   Massachusetts   Department  of  Environmental   Protection  for  the
investigation  and development of a remedial  response plan for the Everett Coal
Tar Facility.

We presently estimate the remaining cost of our environmental cleanup activities
for the three  non-utility  sites will be  approximately  $37.8  million,  which
amount has been  accrued as a  reasonable  estimate of probable  costs for known
sites. Expenditures incurred since November 8, 2000, with respect to these sites
total $5.1 million.

We believe that in the aggregate,  the accrued  liability for  investigation and
remediation  of sites and related  facilities  identified  above are  reasonable
estimates of likely cost within a range of  reasonable,  foreseeable  costs.  We
continually  evaluate our recorded  liability  for  clean-up  activities  and as
circumstances arise we may revise our reserves  accordingly.  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, 2002
Note 7 to those Consolidated Financial Statements  "Contractual  Obligations and
Contingencies" for further information on environmental matters.

Legal Matters

From time to time we are subject to various legal proceedings arising out of the
ordinary  course of our  business.  Except as described  below,  or in KeySpan's
Annual  Report on Form 10-K for the year  ended  December  31,  2002,  KeySpan's
Quarterly Reports on Form 10-Q for the periods ended March 31, 2003 and June 30,
2003 and KeySpan's  Current Report on Form 8-K dated October 15, 2003, we do not
consider  any of such  proceedings  to be material to our  business or likely to
result in a material  adverse  effect on our  results of  operations,  financial
condition or cash flows.


                                       23
<PAGE>

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.

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

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

KeySpan  subsidiaries,  along with  several  other  parties,  have been named as
defendants in numerous  proceedings filed by plaintiffs claiming various degrees
of injury from asbestos exposure at generating facilities formerly owned by Long
Island Lighting Company and others.  As previously  disclosed,  in March 2003, a
jury rendered a verdict against our subsidiary, KeySpan Generation LLC ("KeySpan
Generation"),  and other defendants in the amount of $47 million in a proceeding
filed by a plaintiff  claiming  injury  from  asbestos  exposure  at  generating
facilities  formerly  owned by the Long Island  Lighting  Company  ("LILCO") and
others.  In October 2003,  KeySpan  Generation agreed to pay $400,000 to resolve
this matter and a stipulation discontinuing this lawsuit has been filed with the
court.


                                       24
<PAGE>

In connection with the May 1998 transaction with LIPA, costs incurred by KeySpan
for  liabilities  for  asbestos  exposure  arising  from the  activities  of the
generating facilities previously owned by LILCO, including the facility involved
in the case  referred  to above,  are  recoverable  from LIPA  through the Power
Supply Agreement between LIPA and KeySpan.

KeySpan is unable to  determine  the outcome of the other  outstanding  asbestos
proceedings,  but does not believe that such outcomes,  if adverse,  will have a
material effect on its financial condition,  results of operation or cash flows.
KeySpan believes that its cost recovery rights under the Power Supply Agreement,
its  indemnification  rights  against third  parties and its insurance  coverage
(above applicable deductible limits) cover its exposure for asbestos liabilities
generally.

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  was  seeking  damages in excess of $90 million and
KeySpan  alleged  a number  of  counterclaims  seeking  damages  in excess of $4
million.  In June 2003,  the parties  entered  into an agreement  settling  this
matter and a stipulation  discontinuing  the lawsuit,  with prejudice,  has been
filed with the court.  The settlement will not have a material adverse effect on
the financial condition,  results of operations or cash flows of KeySpan.  Under
the terms of the  settlement,  which was modified in September 2003, (i) certain
obligations  between the parties have been modified and clarified,  (ii) certain
contracts were awarded to Hawkeye, (iii) certain credit and bonding support made
available by KeySpan to Hawkeye will be curtailed and ultimately  terminated and
(iv) in  addition  to a  short-term  bridge  loan of $21  million  in June 2003,
KeySpan will provide a fully secured, interest bearing loan of up to $55 million
in the  aggregate,  to  finance a power  plant  that has been  constructed  by a
Hawkeye  affiliate.  In October  2003,  KeySpan  and  Hawkeye  closed on the $55
million  long-term loan and the $21 million  short-term  bridge loan was paid in
full.

Financial Guarantees

KeySpan  has  issued  financial  guarantees  in the normal  course of  business,
primarily on behalf of its  subsidiaries,  to various third party creditors.  At
September 30, 2003,  the  following  amounts would have to be paid by KeySpan in
the event of non-payment by the primary obligor at the time payment is due:


                                       25
<PAGE>

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
                                                                          Amount of       Expiration
Nature of Guarantee (In Thousands of Dollars)                              Exposure         Dates
----------------------------------------------------------------------------------------------------------
<S>                                                         <C>          <C>             <C>
Medium-Term Notes - KEDLI                                    (i)        $   525,000       2008-2010
Master Lease  - Ravenswood                                   (ii)           425,000         2004
Surety Bonds                                                 (iii)          250,068       Revolving
Commodity Guarantees and Other                               (iv)            73,842         2005
Letters of Credit                                            (v)             64,822         2003
----------------------------------------------------------------------------------------------------------

Surety Bonds                                                 (vi)            11,540       Revolving
Third Party Line of Credit                                   (vi)            25,000         2004
----------------------------------------------------------------------------------------------------------
                                                                        $ 1,375,272
----------------------------------------------------------------------------------------------------------
</TABLE>

The  following is a  description  of  KeySpan's  outstanding  guarantees  of the
obligations of its subsidiaries:

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

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

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

(iv) KeySpan has guaranteed  commodity-related  payments for subsidiaries within
     the Energy  Services  segment,  as well as KeySpan  Ravenswood,  LLC. These
     guarantees  are  provided  to third  parties  to  facilitate  physical  and
     financial  transactions  involved in the  purchase of natural  gas, oil and
     other petroleum products for electric production and marketing  activities.
     The guarantees cover actual purchases by these subsidiaries that were still
     outstanding as of September 30, 2003.


                                       26
<PAGE>

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

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

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

(vi) At September 30, 2003, KeySpan had agreed to support a line of credit up to
     $25 million on behalf of Hawkeye,  a non-affiliated  company.  In addition,
     KeySpan had also guaranteed certain  performance bonds of Hawkeye. To date,
     we have not had a claim made against either the guarantee  associated  with
     the line of credit or the  performance  bonds.  In June 2003,  KeySpan  and
     Hawkeye  settled an outstanding  legal  proceeding.  In connection with the
     settlement  discussed  previously,  our obligation to guarantee the line of
     credit has been terminated.  Further,  we are no longer required to provide
     support for Hawkeye's surety bonds.  (See Legal Matters above for a summary
     of the settlement)

9. VARIABLE INTEREST ENTITY

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

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


                                       27
<PAGE>

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

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

Prospectively,  KeySpan  will have a $425  million  asset that will be amortized
over the economic life of the leased  property.  However,  upon  implementation,
there will be a cumulative catch-up adjustment for a change in accounting policy
as if the asset had been owned from inception, or June 20, 1999. At December 31,
2003,  KeySpan  will be deemed  to have  owned and  depreciated  the asset  from
inception,  or for  approximately  4.5  years.  Therefore,  assuming  a  35-year
economic life, it is  anticipated  that an after-tax  charge of $34 million,  or
$0.22 per share,  will be recorded as a change in  accounting  principle  on the
Consolidated  Statement of Income. Upon implementation of FIN 46, therefore,  we
anticipate  recording an asset of approximately  $362 million and debt of $412.3
million.

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

10. STOCK OPTIONS

Stock options have been issued to KeySpan officers,  directors and certain other
management  employees  and  consultants  as approved by the Board of  Directors.
These  options  generally  vest  over a  three-to-five  year  period  and have a
ten-year exercise period.  Moreover,  under a separate plan, Houston Exploration
has issued stock options to its directors and key Houston Exploration employees.


                                       28
<PAGE>

During 2002,  KeySpan  announced  its  intention  to record  stock  options as a
compensation  expense  beginning  with those  options  granted in 2003. In 2003,
KeySpan and Houston  Exploration adopted the prospective method of transition in
accordance with SFAS 148  "Accounting for Stock-Based  Compensation - Transition
and  Disclosure."  Accordingly,  compensation  expense  has been  recognized  by
employing  the fair value  recognition  provisions of SFAS 123  "Accounting  for
Stock-Based Compensation" for grants awarded after January 1, 2003.

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

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                        Three Months Ended                    Nine Months Ended
                                                                           September 30,                        September 30,
(In Thousands of Dollars, Except Per Share Amounts)                   2003              2002               2003               2002
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>               <C>               <C>                <C>
Earnings available for common stock:                                $ 11,124          $ 3,629          $ 245,529          $ 224,818
As reported
     Add: recorded stock-based compensation expense, net of tax          868               78              3,132                144
     Deduct: total stock-based compensation expense, net of tax       (2,707)          (1,887)            (9,043)            (5,661)
------------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings                                                  $  9,285          $ 1,820          $ 239,618          $ 219,301
------------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
     Basic - as reported                                            $   0.07          $  0.03          $    1.56          $    1.60
     Basic - pro-forma                                              $   0.06          $  0.01          $    1.52          $    1.56

     Diluted - as reported                                          $   0.07          $  0.02          $    1.55          $    1.58
     Diluted - pro-forma                                            $   0.06          $  0.01          $    1.51          $    1.55
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

11. KEYSPAN GAS EAST CORPORATION SUMMARY FINANCIAL INFORMATION

KEDLI is a wholly owned  subsidiary of KeySpan.  KEDLI was formed on May 7, 1998
and on May 28, 1998, acquired substantially all of the assets related to the gas
distribution  business of LILCO.  KEDLI  established a program for the issuance,
from  time  to  time,  of up to  $600  million  aggregate  principal  amount  of
Medium-Term  Notes,  which are fully and  unconditionally  guaranteed by KeySpan
Corporation.   On  February  1,  2000,  KEDLI  issued  $400  million  of  7.875%
Medium-Term  Notes due 2010.  In January 2001,  KEDLI issued an additional  $125
million of Medium-Term  Notes at 6.9% due January 2008. The following  condensed
financial  statements  are required to be disclosed by SEC  regulations  and set
forth those of KEDLI,  KeySpan Corporation as guarantor of the Medium-Term Notes
and  our  other  subsidiaries  on a  combined  basis.  The  September  30,  2002
disclosures have been revised to separately present our other subsidiaries.


                                       29
<PAGE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
                            Statement of Income
---------------------------------------------------------------------------------------------------------------------------------
                                                                 Three Months Ended September 30, 2003
(In Thousands of Dollars)                   Guarantor         KEDLI           Other Subsidiaries      Eliminations   Consolidated
---------------------------------------------------------------------------------------------------------------------------------
<S>                                           <C>            <C>                   <C>                <C>            <C>    <C>
Revenues                                     $     185      $  99,170             $ 1,032,644        $    (185)      $ 1,131,814
Operating Expenses
  Purchased gas                                      -         37,038                 136,078                -           173,116
  Fuel and purchased power                           -              -                 132,649                -           132,649
  Operations and maintenance                     6,742         33,457                 467,182                -           507,381
  Intercompany expense                           5,142            310                    (310)          (5,142)                -
  Depreciation and amortization                    (13)        13,519                 122,150                -           135,656
  Operating taxes                                1,824         16,557                  73,409                -            91,790
                                      -------------------------------------------------------------------------------------------
Total Operating Expenses                        13,695        100,881                 931,158           (5,142)        1,040,592

Income from Equity Investments                       -              -                   2,727                -             2,727
                                      -------------------------------------------------------------------------------------------
Operating Income (Loss)                        (13,510)        (1,711)                104,213            4,957            93,949

Interest charges                               (54,233)       (15,661)                (54,205)          45,733           (78,366)
Other income and (deductions)                   67,923         16,812                 (11,939)         (68,391)            4,405
                                      -------------------------------------------------------------------------------------------
Total Other Income and (Deductions)             13,690          1,151                 (66,144)         (22,658)          (73,961)

Income (Loss) Before Income Taxes                  180           (560)                 38,069          (17,701)           19,988

Income Taxes (Benefit)                         (12,574)         1,223                  18,754                -             7,403

                                      -------------------------------------------------------------------------------------------
Net Income (Loss)                            $  12,754      $  (1,783)            $    19,315        $ (17,701)      $    12,585
                                      ===========================================================================================
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                            Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                     Three Months Ended September 30, 2002
(In Thousands of Dollars)                       Guarantor         KEDLI           Other Subsidiaries    Eliminations    Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                              <C>            <C>                    <C>               <C>             <C>
Revenues                                         $   129       $  79,717              $ 998,485          $   (129)      $ 1,078,202
Operating Expenses
  Purchased gas                                        -          35,949                 98,904                 -           134,853
  Fuel and purchased power                             -               -                144,259                 -           144,259
  Operations and maintenance                        (226)         12,447                475,072                 -           487,293
  Intercompany expense                             1,343          19,008                (20,127)             (224)                -
  Depreciation and amortization                      (20)         11,949                115,372                 -           127,301
  Operating taxes                                     (1)         17,534                 71,570                              89,103
                                           -----------------------------------------------------------------------------------------
Total Operating Expenses                           1,096          96,887                885,050              (224)          982,809

Income from Equity Investment                         18               -                  2,281                 -             2,299
                                           -----------------------------------------------------------------------------------------
Operating Income (Loss)                             (949)        (17,170)               115,716                95            97,692

Interest charges                                 (54,116)        (15,073)               (80,057)           69,309           (79,937)
Other income and (deductions)                     55,417           1,765                 12,079           (78,163)           (8,902)
                                           -----------------------------------------------------------------------------------------
Total Other Income and (Deductions)                1,301         (13,308)               (67,978)           (8,854)          (88,839)

Income (Loss) Before Income Taxes                    352         (30,478)                47,738            (8,759)            8,853

Income Taxes (Benefit)                            (4,612)        (11,577)                20,078                 -             3,889
                                           -----------------------------------------------------------------------------------------
Earnings from Continuing Operations              $ 4,964       $ (18,901)             $  27,660          $ (8,759)      $     4,964

Discontinued Operations                                -               -                      -                 -
                                           -----------------------------------------------------------------------------------------
Net Income (Loss)                                $ 4,964       $ (18,901)             $  27,660          $ (8,759)      $     4,964
                                           =========================================================================================
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       30
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                            Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                            Nine Months Ended September 30, 2003
(In Thousands of Dollars)                                 Guarantor      KEDLI       Other Subsidiaries  Eliminations   Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>         <C>    <C>    <C>                 <C>            <C>
Revenues                                                 $     362     $ 754,855      $   4,297,636     $     (362)    $  5,052,491
Operating Expenses
  Purchased gas                                                  -       414,658          1,378,923              -        1,793,581
  Fuel and purchased power                                       -             -            332,647              -          332,647
  Operations and maintenance                                 8,577       104,437          1,402,192              -        1,515,206
  Intercompany expense                                       5,207         2,227             (2,227)        (5,207)               -
  Depreciation and amortization                                (53)       58,503            364,467              -          422,917
  Operating taxes                                                -        57,516            254,238              -          311,754
                                                      ------------------------------------------------------------------------------
Total Operating Expenses                                    13,731       637,341          3,730,240         (5,207)       4,376,105

Income from Equity Investment                                  108             -             12,378              -           12,486
                                                      ------------------------------------------------------------------------------
Operating Income (Loss)                                    (13,261)      117,514            579,774          4,845          688,872

Interest charges                                          (154,113)      (46,771)          (163,224)       137,605         (226,503)
Other income and (deductions)                              395,934         7,786            (53,383)      (397,254)         (46,917)
                                                      ------------------------------------------------------------------------------
Total Other Income and (Deductions)                        241,821       (38,985)          (216,607)      (259,649)        (273,420)

Income (Loss) Before Income Taxes                          228,560        78,529            363,167       (254,804)         415,452

Income Taxes (Benefit)                                     (21,521)       30,756            156,479              -          165,714
                                                      ------------------------------------------------------------------------------
Earnings before Change in Accounting Principle             250,081        47,773            206,688       (254,804)         249,738

Cumulative Effect of Change in Accounting Principle              -             -                174              -              174
                                                      ------------------------------------------------------------------------------
Net Income (Loss)                                        $ 250,081     $  47,773      $     206,862     $ (254,804)    $    249,912
                                                      ==============================================================================
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                      Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                    Nine Months Ended September 30, 2002
(In Thousands of Dollars)                      Guarantor          KEDLI          Other Subsidiaries     Eliminations   Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                              <C>            <C>                  <C>               <C>              <C>
Revenues                                      $     363        $ 536,601            $ 3,633,379       $     (363)      $ 4,169,980
Operating Expenses
  Purchased gas                                       -          241,389                792,764                -         1,034,153
  Fuel and purchased power                            -                -                326,327                -           326,327
  Operations and maintenance                      2,802           37,514              1,497,757                -         1,538,073
  Intercompany expense                            1,482           57,250                (58,369)            (363)                -
  Depreciation and amortization                     (23)          47,530                333,251                -           380,758
  Operating taxes                                     -           62,228                220,435                -           282,663
                                       --------------------------------------------------------------------------------------------
Total Operating Expenses                          4,261          445,911              3,112,165             (363)        3,561,974

Income from Equity Investments                       52                -                  9,661                              9,713
                                       --------------------------------------------------------------------------------------------
Operating Income (Loss)                          (3,846)          90,690                530,875                -           617,719

Interest charges                               (148,878)         (46,175)              (216,481)         188,940          (222,594)
Other income and (deductions)                   371,281            6,860                 39,567         (418,485)             (777)
                                       --------------------------------------------------------------------------------------------
Total Other Income and (Deductions)             222,403          (39,315)              (176,914)        (229,545)         (223,371)

Income (Loss) Before Income Taxes               218,557           51,375                353,961         (229,545)          394,348

Income Taxes (Benefit)                          (10,548)          22,783                133,346                -           145,581

                                       --------------------------------------------------------------------------------------------
Earnings from Continuing Operations             229,105           28,592                220,615         (229,545)          248,767
Discontinued Operations                               -                                 (19,662)                           (19,662)
                                       --------------------------------------------------------------------------------------------
Net Income (Loss)                             $ 229,105        $  28,592            $   200,953       $ (229,545)      $   229,105
                                       ============================================================================================
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       31
<PAGE>

<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
------------------------------------------------------------------------------------------------------------------------------------
                                                                                 September 30, 2003
                                               Guarantor            KEDLI       Other Subsidiaries     Eliminations     Consolidated
                                         -------------------------------------------------------------------------------------------
<S>                                           <C>                <C>               <C>                <C>               <C>
ASSETS
Current Assets
   Cash & temporary cash investments          $    21,548       $     3,039       $     93,464       $          -      $    118,051
   Accounts receivable, net                        34,300           141,246            982,236                  -         1,157,782
   Other current assets                             3,880           138,104            589,777                  -           731,761
                                         -------------------------------------------------------------------------------------------
                                                   59,728           282,389          1,665,477                  -         2,007,594
                                         -------------------------------------------------------------------------------------------

Investments and Other                           3,981,367             2,542            221,121         (3,912,443)          292,587
                                         -------------------------------------------------------------------------------------------
Property
   Gas                                                  -         1,852,102          4,545,604                            6,397,706
   Other                                                -                 -          5,345,573                            5,345,573
   Accumulated depreciation and depletion               -          (346,869)        (3,703,508)                          (4,050,377)
                                         -------------------------------------------------------------------------------------------
                                                        -         1,505,233          6,187,669                  -         7,692,902
                                         -------------------------------------------------------------------------------------------

Intercompany Accounts Receivable                3,753,148                 -         (3,753,148)                                   -

Deferred Charges                                  325,297           184,347          6,939,954         (4,442,633)        3,006,965

                                         -------------------------------------------------------------------------------------------
Total Assets                                  $ 8,119,540       $ 1,974,511       $ 11,261,073       $ (8,355,076)     $ 13,000,048
                                         ===========================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                           $    67,610       $    62,503          $ 762,932                         $    893,045
   Commercial paper                               644,400                 -                  -                              644,400
   Other current liabilities                      263,667            85,066             13,378                              362,111
                                         -------------------------------------------------------------------------------------------
                                                  975,677           147,569            776,310                  -         1,899,556
                                         -------------------------------------------------------------------------------------------
Intercompany Accounts Payable                           -           172,501          2,138,748         (2,311,249)                -
                                         -------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                               (44,539)          177,952            842,945                              976,358
Other deferred credits and liabilities            480,288            80,724            501,209                            1,062,221
                                         -------------------------------------------------------------------------------------------
                                                  435,749           258,676          1,344,154                  -         2,038,579
                                         -------------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                     3,575,954           694,861          3,214,914         (3,912,443)        3,573,286
Preferred stock                                    83,697                 -                  -                  -            83,697
Long-term debt                                  3,048,463           700,904          3,309,440         (2,131,384)        4,927,423
                                         -------------------------------------------------------------------------------------------
Total Capitalization                            6,708,114         1,395,765          6,524,354         (6,043,827)        8,584,406
                                         -------------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies               -                 -            477,507                  -           477,507
                                         -------------------------------------------------------------------------------------------
Total Liabilities & Capitalization            $ 8,119,540       $ 1,974,511       $ 11,261,073       $ (8,355,076)     $ 13,000,048
                                         ===========================================================================================
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>




                                       32
<PAGE>

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

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

Intercompany Accounts Receivable                 3,619,515               -            712,394         (4,331,909)                 -

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

                                         -------------------------------------------------------------------------------------------
Total Assets                                   $ 7,870,969     $ 1,939,103       $ 10,872,522       $ (8,068,288)      $ 12,614,306
                                         ===========================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                            $   132,966     $    68,772       $    859,911       $          -       $  1,061,649
   Commercial paper                                915,697               -                  -                  -            915,697
   Other current liabilities                       107,605         104,975             30,302                  -            242,882
                                         -------------------------------------------------------------------------------------------
                                                 1,156,268         173,747            890,213                  -          2,220,228
                                         -------------------------------------------------------------------------------------------
Intercompany Accounts Payable                            -         178,843          2,071,682         (2,250,525)                 -
                                         -------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                                (43,110)        139,715            780,408                  -            877,013
Other deferred credits and liabilities             481,964          98,805            453,353                  -          1,034,122
                                         -------------------------------------------------------------------------------------------
                                                   438,854         238,520          1,233,761                  -          1,911,135
                                         -------------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                      2,983,214         647,089          3,050,668         (3,736,379)         2,944,592
Preferred stock                                     83,849               -                  -                  -             83,849
Long-term debt                                   3,208,784         700,904          3,395,777         (2,081,384)         5,224,081
                                         -------------------------------------------------------------------------------------------
Total Capitalization                             6,275,847       1,347,993          6,446,445         (5,817,763)         8,252,522
                                         -------------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies                -               -            230,421                  -            230,421
                                         -------------------------------------------------------------------------------------------
Total Liabilities & Capitalization             $ 7,870,969     $ 1,939,103       $ 10,872,522       $ (8,068,288)      $ 12,614,306
                                         ===========================================================================================
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       33
<PAGE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
---------------------------------------------------------------------------------------------------------------------------------
                                                                                  Nine Months Ended September 30, 2003
                                                               ------------------------------------------------------------------
                                                                     Guarantor        KEDLI       Other Subsidiaries  Consolidated
                                                               ------------------------------------------------------------------
<S>                                                                  <C>            <C>               <C>              <C>
Operating Activities
Net Cash Provided by Operating Activities                           $  55,555       $ 85,143          $ 596,365        $ 737,063
                                                               ------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                     -        (82,233)          (637,984)        (720,217)
  Other investments                                                         -              -            (50,500)         (50,500)
   Proceeds from the sale of investments and property                  79,200              -            133,327          212,527
                                                               ------------------------------------------------------------------
Net Cash Provided by (Used in) Investing Activities                    79,200        (82,233)          (555,157)        (558,190)
                                                               ------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                               76,984              -                  -           76,984
   Equity issuance                                                    473,573              -                  -          473,573
   Redemption of promissory notes                                    (447,005)             -                  -         (447,005)
   Payment of debt and preferred stock, net                            28,703              -           (168,324)        (139,621)
   Common and preferred stock dividends paid                         (208,178)             -                  -         (208,178)
   Other                                                               17,240              -             (4,432)          12,808
   Net intercompany accounts                                         (142,833)        (6,342)           149,175                -
                                                                                                                               -
                                                               ------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities                  (201,516)        (6,342)           (23,581)        (231,439)
                                                               ------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                $ (66,761)      $ (3,432)         $  17,627        $ (52,566)
Cash and Cash Equivalents at Beginning of Period                       88,308          6,472             75,837          170,617
                                                               ------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                          $  21,547       $  3,040          $  93,464        $ 118,051
                                                               ==================================================================
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                      Nine Months Ended September 30, 2002
                                                             ----------------------------------------------------------------------
                                                                    Guarantor          KEDLI       Other Subsidiaries   Consolidated
                                                             ----------------------------------------------------------------------
<S>                                                                <C>               <C>              <C>                <C>
Operating Activities
Net Cash Provided by (Used in) Operating Activities                $ (294,829)      $ 180,694         $ 869,456          $ 755,321
                                                             ----------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                     -        (101,844)         (713,311)          (815,155)
   Proceeds from sale of investments                                        -               -           173,935            173,935
                                                             ----------------------------------------------------------------------
Net Cash Used in Investing Activities                                       -        (101,844)         (539,376)          (641,220)
                                                             ----------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                               67,308                                 -             67,308
   Payment of debt, net                                               (59,222)                          (35,378)           (94,600)
   Common and preferred stock dividends paid                         (192,144)                                -           (192,144)
   Other                                                                 (244)                              253                  9
   Net intercompany accounts                                          542,945         (78,850)         (464,095)                 -

                                                             ----------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities                   358,643         (78,850)         (499,220)          (219,427)
                                                             ----------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                 $ 63,814             $ -        $ (169,140)        $ (105,326)
Cash and Cash Equivalents at Beginning of Period                            -               -           159,252            159,252
                                                             ----------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                           $ 63,814             $ -          $ (9,888)          $ 53,926
                                                             ======================================================================
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       34
<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,  2003,  compared to the three and nine months
ended September 30, 2002.  Capitalized  terms used in the following  discussion,
but not  otherwise  defined,  have the same meaning as when used in the Notes to
the  Consolidated  Financial  Statements  included  under Item 1.  References to
"KeySpan",  "we," "us," and "our" mean KeySpan  Corporation,  together  with its
consolidated subsidiaries.

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

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars, Except per Share)
---------------------------------------------------------------------------------------------------------------------------------
                                                               Three Months Ended                          Nine Months Ended
                                                                  September 30,                              September 30,
                                                            2003                 2002                  2003               2002
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>                <C>                    <C>                 <C>
Gas Distribution                                         $ (39,108)         $ (39,565)             $ 357,445           $ 321,551
Electric Services                                          100,254            106,611                191,404             227,613
Energy Services                                            (13,627)            (4,834)               (32,647)            (25,056)
Energy Investments                                          59,004             36,880                183,940              90,714
Eliminations and other                                     (12,574)            (1,400)               (11,270)              2,897
---------------------------------------------------------------------------------------------------------------------------------
Operating Income                                            93,949             97,692                688,872             617,719
Other Income and (Deductions)                              (73,961)           (88,839)              (273,420)           (223,371)
Income taxes                                                 7,403              3,889                165,714             145,581
---------------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations                           12,585              4,964                249,738             248,767
Cumulative effect of a change
   in accounting principle                                       -                  -                    174                   -
Discontinued operations                                          -                  -                      -             (19,662)
---------------------------------------------------------------------------------------------------------------------------------
Net Income                                                  12,585              4,964                249,912             229,105
Preferred stock dividend requirements                        1,461              1,335                  4,383               4,287
---------------------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock                                $  11,124          $   3,629              $ 245,529           $ 224,818
---------------------------------------------------------------------------------------------------------------------------------
Basic Earnings per Share
   Income from continuing operations                     $    0.07          $    0.03              $    1.56           $    1.74
   Change in accounting principle                                -                  -                      -                   -
   Discontinued operations                                       -                  -                      -               (0.14)
---------------------------------------------------------------------------------------------------------------------------------
                                                         $    0.07          $    0.03              $    1.56           $    1.60
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

As indicated in the above table,  operating income decreased $3.7 million, or 4%
for the three months ended  September 30, 2003,  compared to the same quarter of
last year. These results reflect lower operating income from the Energy Services
and Electric Services  segments,  as well as a higher level of overall corporate
overhead costs,  offset,  in part, by higher operating  earnings from the Energy
Investment  segment.  The Energy  Services  group of  companies,  continue to be
adversely  impacted  by  the  softness  in  the  construction  industry  in  the
northeastern  United States.  The lower  operating  income  associated  with the
Electric  Services  segment  reflects  lower  revenues  from  KeySpan's  service
agreements  with the Long Island  Power  Authority  ("LIPA"),  as well as higher
operating costs. The Energy  Investment  segment  benefited from higher earnings
associated  with gas  exploration  and  production  activities  as a  result  of
significantly higher realized gas prices.


                                       35
<PAGE>

For the nine months ended September 30, 2003,  operating  income increased $71.2
million,  or 12% compared to the  corresponding  period of the prior year.  This
increase  in  operating   income   reflects  higher  earnings  from  the  Energy
Investments  and Gas  Distribution  segments,  somewhat  offset by  decreases in
earnings from the Electric Services and Energy Services  segments,  as well as a
higher level of overall corporate  overhead costs. The Energy Investment segment
benefited from higher  earnings  associated  with gas exploration and production
activities  as a result of  significantly  higher  realized gas prices.  The Gas
Distribution  segment  benefited from colder weather during the January  through
April 2003 heating season compared to the same period last year, as well as from
load growth.  Lower results from the Electric  Services segment are attributable
to higher operating costs as a result of increases in plant maintenance expenses
and pension and other  postretirement  costs, as well as lower revenues from our
merchant generating  facility,  due, in part to cooler summer weather.  (See the
discussion under the caption "Review of Operating  Segments" for further details
on each segment.)

Included in Other Income and  (Deductions) are interest charges of $78.4 million
and $226.5  million  for the three and nine months  ended  September  30,  2003,
respectively.  Comparative  interest  charges for the third  quarter of 2003 are
virtually  the same  compared  to the third  quarter of 2002.  The  increase  in
interest charges of 2% for the nine months ended September 30, 2003, compared to
the same  period  last  year,  primarily  reflects  the  termination  of certain
interest-rate derivative swap instruments that were in effect in 2002. (See Note
6 to the Consolidated  Financial  Statements  "Hedging and Derivative  Financial
Instruments.") For the third quarter of 2003, Other Income and (Deductions) also
reflects a $14.0  million  pre-tax  gain ($8.4  million  after-tax  or $0.05 per
share) for the sale of 550 acres of real  property  located on Long Island.  The
amount of the gain is subject to  adjustment  as we are currently in the process
of defining  the tax basis of the assets  sold.  In  addition,  during the three
months ended  September  30, 2003,  The Houston  Exploration  Company  ("Houston
Exploration"), our gas exploration and production subsidiary, recorded severance
tax refunds of $6.2 million,  as a result of an abatement of severance taxes for
certain qualifying wells.

For the nine months ended September 30, 2003, Other Income and (Deductions) also
reflects  the  impact  from  the  monetization  of a  portion  of  our  Canadian
investments,  as  well  as a  portion  of  our  ownership  interest  in  Houston
Exploration.  In June 2003, we sold 39.09% of our interest in KeySpan Canada,  a
company with natural gas processing  plants and gathering  facilities in Western
Canada.  Additionally,  we sold our 20%  interest in Taylor NGL LP that owns and
operates  two  extraction  plants also in Canada.  We recorded a pre-tax loss of
$30.3 million ($34.1 million after-tax) associated with these sales. (See Note 2
to the  Consolidated  Financial  Statements  "Business  Segments" for additional
information  regarding  this  transaction.)  Additionally,  in February 2003, we
reduced our ownership interest in Houston  Exploration from 66% to approximately
56% following the repurchase, by Houston Exploration, of three million shares of
common  stock  owned by  KeySpan.  We  recorded a gain of $19.0  million on this
transaction.  Income  taxes were not  provided  on this  transaction,  since the
transaction was structured as a return of capital.


                                       36
<PAGE>


In March 2003, we called  approximately  $447 million of outstanding  promissory
notes  that  were  issued to LIPA in  connection  with the  KeySpan/Long  Island
Lighting  Company  ("LILCO")  business  combination  completed  in May 1998.  We
recorded  debt  redemption   charges  of  $18.2  million  associated  with  this
redemption which is also recorded in Other Income and (Deductions).  Further, in
June 2003,  Houston  Exploration  incurred  costs of $5.9 million to retire $100
million 8.625% Notes due 2008.

Additionally,  for the nine months ended  September  30, 2003,  Other Income and
(Deductions)  reflects  severance tax refunds totaling $19.1 million recorded by
Houston  Exploration  for severance taxes paid in 2002 and earlier  periods,  as
well the sale of the  non-utility  property,  as noted earlier.  Finally,  Other
Income and (Deductions)  reflects  adjustments for minority  interest related to
Houston  Exploration and KeySpan Canada,  as well as carrying charges on certain
regulatory assets.

Income tax expense for the three and nine months  ended  September  30, 2003 and
2002,  reflects a number of items  impacting  comparative  earnings.  During the
third quarter of 2003, we recorded a tax benefit of $9.0 million associated with
certain New York City general corporation tax issues.  Further,  during the nine
months ended September 30, 2003, certain costs associated with employee deferred
compensation  plans were deducted for federal income tax purposes.  These costs,
however,  are  not  expensed  for  "book"  purposes  resulting  in a  beneficial
permanent  book-to-tax  difference  of $6.3  million.  In addition,  the partial
monetization  of our  Canadian  investments  resulted  in a tax  expense of $3.8
million, reflecting certain United States partnership tax rules.

Income tax expense for the nine months ended  September  30, 2002 reflects a tax
benefit  of $6.4  million  as a result of the  favorable  resolution  of certain
outstanding tax issues related to the KeySpan/LILCO merger. Additionally, during
the first quarter of 2002, we recorded an adjustment to deferred income taxes of
$177.7 million  reflecting a decrease in the tax basis of the assets acquired at
the time of the  merger.  This  adjustment  was a result of a revised  valuation
study and the filing of an amended tax return.  Concurrent with the deferred tax
adjustment, we reduced current income taxes payable by $183.2 million, resulting
in a $5.5 million income tax benefit.

Also, it should be noted that pre-tax  income in the  Consolidated  Statement of
Income reflects minority interest adjustments,  whereas income taxes reflect the
full amount of  subsidiary  taxes.  Excluding all of the  aforementioned  items,
income taxes generally reflects the level of pre-tax earnings for all periods.

In January 2002, KeySpan announced that it had entered into an agreement to sell
Midland  Enterprises  LLC  ("Midland"),  its marine barge  business.  During the
fourth quarter of 2001, in anticipation of this  divestiture that closed on July
2, 2002, an estimated  loss on the sale of Midland was  recorded,  as well as an
estimate for Midland's  results of operations for the first nine months of 2002.
In the second quarter of 2002, we recorded an additional after-tax loss of $19.7
million,  primarily reflecting a provision for certain city and state taxes that
resulted from a change in our tax structuring strategy.


                                       37
<PAGE>


As a result of the above mentioned  items,  earnings  available for common stock
for the three months ended  September 30, 2003 increased $7.5 million,  or $0.04
per share,  compared to the same quarter of last year.  Earnings  available  for
common  stock for the nine  months  ended  September  30, 2003  increased  $20.7
million. Earnings per share, however,  decreased by $0.04 per share, compared to
the same period last year,  reflecting  the issuance of 13.9  million  shares of
common stock on January 17, 2003, as well as the  re-issuance  of shares held in
treasury  pursuant to dividend  reinvestment  and employee  benefit  plans.  The
increase in average common shares outstanding  reduced nine months 2003 earnings
per share by $0.18 compared to the corresponding period in 2002. To mitigate the
dilutive  effect of the equity  offering,  a portion of  outstanding  promissory
notes that were issued to LIPA were redeemed, as previously mentioned.  Interest
savings  associated  with this  redemption  are  estimated  to be $15.6  million
after-tax, or $0.09 per share, in 2003.

Consistent  with our prior  earnings  guidance,  KeySpan  earnings  for 2003 are
forecasted to be approximately $2.45 to $2.60 per share, including the effect of
the equity issuance in January 2003 and excluding  special items.  Earnings from
continuing  core  operations   (defined  for  this  purpose  as  all  continuing
operations  other  than   exploration  and  production,   less  preferred  stock
dividends) are  forecasted to be  approximately  $2.15 to 2.20 per share,  while
earnings  from  exploration  and  production  operations  are  forecasted  to be
approximately  $0.30  to  $0.40  per  share.  The  earnings  forecasts  may vary
significantly during the year due to, among other things,  changing economic and
energy  market  conditions,  commodity  prices  and  weather,  and  may  vary by
operating segment as well.

Consolidated earnings are seasonal in nature due to the significant contribution
to earnings of the gas distribution  operations.  As a result, we expect to earn
most of our annual earnings in the first and fourth quarters of our fiscal year.

Review of Operating Segments

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

Gas Distribution

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


                                       38
<PAGE>


The table below  highlights  certain  significant  financial  data and operating
statistics  for the Gas  Distribution  segment  for the periods  indicated.  Net
revenues for 2002 have been  restated by $1.8 million and $10.1  million for the
three and nine  months  ended  September  30,  2002,  respectively  to reflect a
reclassification  of gross  receipt  taxes from  revenue  taxes to state  income
taxes, which is not an Operating Income measure.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
                                                             Three Months Ended                          Nine Months Ended
                                                                September 30,                             September 30,
(In Thousands of Dollars)                                2003                2002                   2003                 2002
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>                 <C>                   <C>                  <C>
Revenues                                              $ 405,777           $ 334,031             $ 2,970,514          $ 2,078,823
Cost of gas                                             173,116             126,944               1,744,732              976,884
Revenue taxes                                            10,191               8,830                  66,077               56,974
---------------------------------------------------------------------------------------------------------------------------------
Net Revenues                                            222,470             198,257               1,159,705            1,044,965
---------------------------------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                           163,372             147,023                 492,586              445,330
   Depreciation and amortization                         59,996              56,174                 197,005              177,312
   Operating taxes                                       38,210              34,625                 112,669              100,772
---------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                261,578             237,822                 802,260              723,414
---------------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss)                               $ (39,108)          $ (39,565)              $ 357,445            $ 321,551
---------------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH)                 26,668              25,768                 238,382              190,264
Transportation - Electric Generation (MDTH)              15,567              27,709                  29,715               54,250
Other Sales (MDTH)                                       35,157              51,949                 113,309              153,974
Warmer (Colder) than Normal - New York                      N/A                 N/A                    (13%)                 15%
Warmer (Colder) than Normal - New England                   N/A                 N/A                    (17%)                 10%
---------------------------------------------------------------------------------------------------------------------------------
</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.

Net Revenues

Net gas revenues  (revenues less the cost of gas and  associated  revenue taxes)
from our gas distribution  operations  increased by $114.7 million,  or 11%, for
the nine months ended September 30, 2003, compared to the same period last year.
Both our New York and New England based gas  distribution  operations  benefited
from the  significantly  colder than normal weather  experienced  throughout the
northeastern  United States  during this past winter  heating  season.  Based on
heating  degree days,  weather for the nine months ended  September 30, 2003 was
approximately 12%-16% colder than normal and approximately 30% - 35% colder than
last year in our New York and New England service territories.


                                       39
<PAGE>


Net revenues from firm gas customers  (residential,  commercial  and  industrial
customers) in our New York service territory  increased by $60.6 million for the
nine months ended  September  30,  2003,  compared to the same period last year.
Customer   additions   and   oil-to-gas   conversions,   net  of  attrition  and
conservation,  added  approximately  $15 million to net revenues during the nine
months.  Higher customer consumption due primarily to colder than normal weather
added approximately $50 million to net revenues during the nine months. However,
KEDNY and KEDLI each  operate  under a utility  tariff  that  contains a weather
normalization  adjustment  that  significantly  offsets  variations  in firm net
revenues due to  fluctuations  in normal  weather.  These weather  normalization
adjustments  resulted in a $26 million  refund to firm gas customers  during the
past nine months.  Further,  included in net revenues are regulatory  incentives
and  recovery  of  certain  taxes that added  $6.5  million  and $15.1  million,
respectively  to net  revenues  during this time  period.  The recovery of taxes
through revenues,  however,  does not impact net income since the taxes they are
designed to recover are expensed as  amortization  charges and income taxes,  as
appropriate, on the Consolidated Statement of Income.

Net  revenues  from firm gas  customers  in our New  England  service  territory
increased  by $26.8  million  for the nine  months  ended  September  30,  2003,
compared  to the same  period  last  year.  Customer  additions  and  oil-to-gas
conversions, net of attrition and conservation, added approximately $9.5 million
to net  revenues  during  the  nine  months.  Higher  customer  consumption  due
primarily to colder than normal weather added  approximately  $33 million to net
revenues during the past nine months. The gas distribution operations of our New
England based subsidiaries do not have a weather  normalization  adjustment.  To
mitigate  the  effect of  fluctuations  in normal  weather  patterns  on KEDNE's
results of operations and cash flows,  weather derivatives were put in place for
the 2002/2003  winter heating season.  Since weather during the first quarter of
2003 was 10%  colder  than  normal  in the New  England  service  territory,  we
recorded  an $11.9  million  reduction  to revenues to reflect the loss on these
derivative  transactions.  (See Note 6 to the Consolidated  Financial Statements
"Hedging  and  Derivative  Financial   Instruments"  for  further  information).
Further, included in net revenues for the period ended September 30, 2002, was a
benefit of $3.9 million as a result of a favorable ruling from the Massachusetts
Supreme  Judicial  Court  relating  to the appeal by Boston  Gas  Company of its
Performance Based Rate Plan ("PBR").

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

In our large-volume  heating and other interruptible  (non-firm) markets,  which
include large apartment houses, government buildings and schools, gas service is
provided  under rates that are  designed to compete  with prices of  alternative
fuel,  including  No. 2 and No. 6 grade  heating oil. Net revenues from sales to
these markets  increased by $27.3 million during the nine months ended September
30,  2003,  compared  to same period last year.  The  majority of  interruptible
profits earned by KEDNE and KEDLI are returned to firm customers as an offset to
gas costs.

We are  committed  to our  expansion  strategies  initiated  during the past few
years. We believe that significant growth opportunities exist on Long Island and
in our New  England  service  territories.  We  estimate  that  on  Long  Island
approximately 35% of the residential and multi-family markets, and approximately
55% of the  commercial  market,  currently  use natural  gas for space  heating.


                                       40
<PAGE>

Further, we estimate that in our New England service  territories  approximately
50% of the residential and multi-family  markets,  and  approximately 45% of the
commercial market, currently use natural gas for space heating purposes. We will
continue to seek  growth,  in all our market  segments,  through the  economical
expansion of our gas distribution  system,  as well as through the conversion of
residential  homes from oil-to-gas for space heating purposes and the pursuit of
opportunities  to grow  multi-family,  industrial and commercial  markets.

Firm Sales, Transportation and Other Quantities

Firm gas sales and  transportation  quantities  increased by 25% during the nine
months ended  September  30, 2003,  compared to the same period in 2002,  due to
higher  customer  consumption  as a result of the  significantly  colder weather
during the past winter heating  season,  as well as from customer  additions and
oil-to-gas  conversions  to  natural  gas.  Net  revenues  are not  affected  by
customers opting to purchase their gas supply from other sources, since delivery
rates  charged to  transportation  customers  generally are the same as delivery
rates charged to sales service customers.  Transportation  quantities related to
electric generation reflect the transportation of gas to our electric generating
facilities  located on Long  Island.  Net revenues  from these  services are not
material.

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

Purchased Gas for Resale

The increase in gas costs for the nine months ended  September 30, 2003 compared
to the same period in 2002 of $767.8  million,  or 79%,  reflects an increase of
48% in the price per  dekatherm  of gas  purchased,  and a 25%  increase  in the
quantity of gas purchased.  Fluctuations  in utility gas costs  associated  with
firm gas customers have no material impact on operating results. The current gas
rate  structure  of  each  of our  gas  distribution  utilities  includes  a gas
adjustment  clause,  pursuant  to which  variations  between  actual  gas  costs
incurred and gas costs  billed are  deferred  and refunded to or collected  from
customers in a subsequent period.

Operating Expenses

Operating expenses during the third quarter of 2003 increased $23.8 million,  or
10%,  compared to the same quarter last year and $78.9  million,  or 11% for the
nine months ended  September  30,  2003,  compared to the same period last year.
These  increases  are  primarily   attributable  to  higher  pension  and  other
postretirement  benefits,  which have  increased  (net of amounts  deferred  and
subject to regulatory  true-ups) by $9.0 million and $30.1 million for the three
and nine  months  ended  September  30,  2003,  respectively.  The cost of these
benefits has risen primarily as a result of lower actual returns on plan assets,


                                       41
<PAGE>

as well as increased health care costs.  Further, the colder weather experienced
during  the  first  nine  months  of  2003  resulted  in  increased  repair  and
maintenance work on our gas distribution  infrastructure  and higher comparative
operating  expenses.  Also,  for the nine months ended  September 30, 2003,  the
provision for bad debts has increased as a result of higher  revenues due to the
cold weather and higher cost of gas purchased.


Higher depreciation and amortization expense reflects the continued expansion of
the gas distribution system. Further,  included in depreciation and amortization
expense is the amortization of certain  property taxes  previously  deferred and
currently being recovered through revenues.  Comparative operating taxes reflect
a favorable $2.5 million and $9.9 million  adjustment  recorded during the three
and nine months ended September 30, 2002, respectively, relating to the reversal
of excess tax reserves established for the KeySpan / LILCO merger and subsequent
re-organization in May 1998.

Other Matters

In order to serve the  anticipated  market  requirements in our New York service
territory,  KeySpan and Duke Energy  Corporation  formed  Islander East Pipeline
Company,  LLC ("Islander  East") in 2000.  Islander East is owned 50% by KeySpan
and  50% by Duke  Energy,  and was  created  to  pursue  the  authorization  and
construction  of an  interstate  pipeline from  Connecticut,  across Long Island
Sound, to a terminus near Northport, Long Island. Applications for all necessary
regulatory  authorizations  were filed in 2000 and 2001. To date,  Islander East
has received a final certificate from the Federal Energy  Regulatory  Commission
("FERC")  and all  necessary  permits from the State of New York.  However,  the
State of Connecticut has denied  Islander East's  application for a coastal zone
management  permit.  Islander  East has  reinstated  its  appeal of the State of
Connecticut's determination to the United States Department of Commerce. Once in
service,  the pipeline will  transport  260,000 DTH daily to the Long Island and
New York City energy  markets,  enough  natural gas to heat 600,000  homes.  The
pipeline will also allow KeySpan to diversify the geographic  sources of its gas
supply. Various options for the financing of pipeline construction are currently
being evaluated.

Electric Services

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




                                       42
<PAGE>


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

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------
                                                      Three Months                                 Nine Months Ended
                                                   Ended September 30,                               September 30,
(In Thousands of Dollars)                        2003              2002                        2003                2002
---------------------------------------------------------------------------------------------------------------------------
<S>                                           <C>              <C>                         <C>                  <C>
Revenues                                    $   427,687      $   414,893                  $ 1,132,723          $ 1,084,384
Purchased fuel                                  124,789          106,293                      294,547              225,836
---------------------------------------------------------------------------------------------------------------------------
Net Revenues                                    302,898          308,600                      838,176              858,548
---------------------------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                   150,447          149,682                      489,178              481,732
   Depreciation                                  16,410           16,176                       49,054               43,835
   Operating taxes                               35,787           36,131                      108,540              105,368
---------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                        202,644          201,989                      646,772              630,935
---------------------------------------------------------------------------------------------------------------------------
Operating Income                            $   100,254      $   106,611                  $   191,404          $   227,613
---------------------------------------------------------------------------------------------------------------------------
Electric sales (MWH)*                         1,854,740        2,175,937                    3,617,522            4,392,915
Capacity(MW)*                                     2,200            2,200                        2,200                2,200
Cooling degree days                                 824            1,015                        1,000                1,353
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

*Reflects the operations of the Ravenswood facility only.

Net Revenues

Total  electric net  revenues  decreased  by $5.7  million,  or 2%, in the third
quarter of 2003, compared to the same quarter of 2002. For the nine months ended
September 30, 2003, total electric net revenues decreased $20.4 million,  or 2%,
compared to the same period of 2002.

Net revenues from the Ravenswood facility were $7.6 million, or 7% higher during
the third  quarter of 2003,  compared to the same  quarter in 2002.  Comparative
quarterly  net  revenues  reflect  higher  capacity  revenues of $26.8  million,
partially offset by a decrease in energy margins of $19.2 million.  However, for
the nine months ended  September  30, 2003,  net  revenues  from the  Ravenswood
facility  were  $9.4  million,  or 4%  lower  than  the  same  period  of  2002.
Comparative net revenues,  for the nine months ended September 30, 2003, reflect
higher  capacity  revenues  of $25.2  million,  which were more than offset by a
decrease in energy margins of $34.6 million.

The  increase  in  capacity  revenues  for both the  quarter  and  period  ended
September 30, 2003,  reflects an increase in the level of capacity sold, as well
as an increase in the selling price of capacity.  Such  increases are the result
of two  measures.  First,  in 2002,  the New York  Independent  System  Operator
("NYISO")  employed a revised  methodology to assess the available supply of and
demand for installed capacity. This revised methodology resulted in insufficient
capacity  being  procured by the market,  which  caused a  reliability  concern.


                                       43
<PAGE>

Further, the revised methodology resulted in lower capacity volume sold into the
NYISO and  depressed  capacity  pricing  during the  quarter  and  period  ended
September 30, 2002.  The NYISO,  however,  recognized a calculation  flaw in its
revised  methodology  and  prior  to the  2002/2003  winter  auction  the  NYISO
corrected the calculation methodology to ensure sufficient capacity is procured.
Elimination of the flaw ensured compliance with New York State Reliability Rules
and resulted in higher  comparative  capacity revenue realized at the Ravenswood
facility for the three and nine months ended September 30, 2003.

Secondly,  on May 20, 2003,  FERC approved the NYISO's  revised  capacity market
procurement design with an effective date of May 21, 2003. This revised capacity
market  procurement  design is based on a demand  curve  rather than  relying on
deficiency  auctions to procure necessary  capacity.  The deficiency auction and
its  associated  fixed minimum  capacity  requirements  was replaced with a spot
market auction that pays gradually  declining  prices as additional  capacity is
offered and gradually  increasing  prices as capacity offers decrease.  This new
market  design  recognizes  the  value of  capacity  in  excess  of the  minimum
requirement  and reduces price spikes during  periods of shortage.  Essentially,
the demand  curve  design  eliminates  the high and low cycles  inherent  in the
deficiency  auction  market  design.  This new market  design  also  established
seasonal  electric  generator  specific  price caps.  Price caps  establish  the
maximum  price per megawatt hour ("MW") that capacity can be sold into the NYISO
by divested  electric  generators like Ravenswood.  Prior to this design change,
one price cap was  established  for the entire  year and was  effective  for all
electric generators.  For the Ravenswood facility, its 2003 summer price cap was
higher than the yearly price cap effective  during the 2002 summer.  As a result
of these market design changes, the Ravenswood facility realized higher capacity
revenues during the three and nine months ended September 30, 2003,  compared to
the same  periods  in 2002.  It  should  be noted,  however,  that  Ravenswood's
2003/2004  winter  price cap will be lower than the yearly  price cap  effective
during the 2002/2003 winter.

The  decrease  in energy  margins  during  both the  quarter  and  period  ended
September 30, 2003,  primarily reflects  significantly cooler weather during the
summer of 2003 compared to the summer of 2002.  Measured in cooling degree days,
weather for the three and nine months ended  September  30, 2003 was 19% and 26%
cooler than the corresponding  periods last year. The cooler weather resulted in
lower realized  "spark-spreads"  (the selling price of electricity  less cost of
fuel,  plus hedging gains or losses),  as well as a reduction in megawatt  hours
sold into the NYISO.  Further,  more competitive  pricing by electric generators
that bid into the NYISO, as well as certain price mitigation measures imposed by
the FERC (as  discussed  below)  have  resulted  in lower  comparative  realized
"spark-spreads."  As  mentioned,  comparative  energy sales margins for the nine
months ended  September  30, 2003,  also reflect the use of  derivative  hedging
instruments as discussed in more detail below. Energy sales quantities were also
adversely impacted by the major overhaul of our largest steam generator.

We  employ  derivative  financial  hedging  instruments  to hedge  the cash flow
variability  for a portion of  forecasted  purchases of natural gas and fuel oil
that will be consumed at the Ravenswood  facility.  Further,  we have engaged in
the use of  derivative  financial  hedging  instruments  to hedge  the cash flow
variability  associated  with a portion of forecasted peak electric energy sales
from the Ravenswood  facility,  as well as forecasted sales of Unforced Capacity


                                       44
<PAGE>

("UCAP") to the NYISO. These derivative  instruments  resulted in hedging gains,
which are reflected in net energy margins, of $7.9 million and $11.3 million for
the three and nine months ended September 30, 2003, respectively.  For the three
and nine months ended September 30, 2002, these derivative  instruments resulted
in hedging gains of $4.2 million and $15.2 million, respectively. (See Note 6 to
the  Consolidated  Financial  Statements,   "Hedging  and  Derivative  Financial
Instruments for additional information.)

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

Net revenues from the service  agreements  with LIPA decreased by $11.5 million,
or 6% and $22.5 million, or 4% for the three and nine months ended September 30,
2003, respectively, compared to the same periods last year. Included in revenues
are  billings  to LIPA for  certain  third party costs that were lower than such
billings last year.  These  revenues have minimal or no impact on earnings since
we record a similar  amount of costs in operating  expense and we share any cost
under-runs with LIPA.  Excluding  these third party  billings,  revenues for the
three and nine months ended  September  30, 2003  associated  with these service
agreements  decreased  approximately  $3 million and $4  million,  respectively,
compared  to the same  periods  last  year.  These  decreases  are mainly due to
slightly  lower  incentives  earned on the LIPA service  agreements,  as well as
lower sales of emission credits.

Net revenues from the Glenwood  Landing and Port  Jefferson  electric  "peaking"
facilities  located on Long  Island  were $1.8  million  lower  during the third
quarter of 2003  compared  to same period  last year,  reflecting  a decrease in
certain interest charges  "passed-through" to LIPA. These charges have no impact
on net income.  Net revenues  were $11.5  million  higher during the nine months
ended September 30, 2003,  compared to the  corresponding  period last year. The
Glenwood  facility  was  placed  in  service  on June 1,  2002,  while  the Port
Jefferson facility was placed in service on July 1, 2002.

Operating Expenses

Operating  expenses  increased  $0.7 million and $15.8 million for the three and
nine months ended September 30, 2003, respectively, compared to the same periods
of 2002. Included in comparative operating expenses is a decrease in third party
capital  costs  that are  fully  recoverable  from  LIPA,  as noted  previously.


                                       45
<PAGE>

Excluding   the  decrease  in  these   costs,   operating   expenses   increased
approximately  $10 million  and $35 million for the three and nine months  ended
September 30, 2003,  respectively,  compared to the same periods of 2002.  These
increases  resulted,  in part,  from  higher  pension  and other  postretirement
benefits.  LIPA  reimburses  KeySpan for costs  directly  incurred by KeySpan in
providing  service to LIPA,  subject to certain sharing  provisions.  Variations
between  pension and other  postretirement  costs and the estimates used to bill
LIPA are deferred and refunded to or collected from LIPA in subsequent  periods.
As a result  of an  adjustment  recorded  in 2002  relating  to this  "true-up",
comparative pension and other postretirement costs were approximately $1 million
and $9 million  higher for the three and nine months  ended  September  30, 2003
compared to the same periods last year.  Further,  plant  maintenance costs were
$5.3 million  higher for the nine months ended  September  30, 2003,  due to the
major overhaul of our largest steam generator at the Ravenswood facility site as
previously mentioned.  In addition,  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  in  2002.  The  increase  in
depreciation  expense is primarily due to the  depreciation  of the Glenwood and
Port Jefferson peaking facilities.

Other Matters

On August  14,  2003,  at  approximately  4:15 PM  eastern  standard  time,  the
northeastern  United  States  experienced  a  major  black-out.  The  Ravenswood
electric  generating units were out of service for up to 23 hours. The NYISO, in
an attempt to  mitigate  the  economic  damage to electric  generators  and load
serving entities from the black-out, revised its day-ahead and real-time pricing
mechanisms. We estimate that the lost opportunity of not selling electric energy
into the  NYSIO,  while the  various  Ravenswood  generating  units  were out of
service, to be between $1 million to $2 million on a net margin basis.

During  2002,  construction  began  on a new 250 MW  combined  cycle  generating
facility  at the  Ravenswood  facility  site.  The new  facility  is expected to
commence operational testing in late 2003. The capacity and energy produced from
this plant are  anticipated  to be sold into the NYISO energy markets by the end
of the first  quarter of 2004. We anticipate  replacing  outstanding  commercial
paper related to the  construction of this facility with permanent  financing by
the end of the second quarter of 2004.

Our  application  to  construct  and  operate a 250 MW combined  cycle  electric
generating facility in Melville,  Long Island has been approved. In May, the New
York State Board on Electric  Generation  Siting and the  Environment  issued an
opinion and order which granted a certificate  of  environmental  capability and
public need for this proposed facility,  which is now final and  non-appealable.
Also in May 2003, LIPA issued a Request for Proposals  ("RFP") seeking proposals
from developers to either build and operate a Long Island  generating  facility,
and/or a new cable that will link Long Island to dedicated off-Long Island power
of between 250 to 600 MW of  electricity by no later than the summer of 2007. In
September,  KeySpan  and  American  National  Power Inc.  ("ANP")  filed a joint
proposal in response to LIPA's  RFP.  Under the  proposal,  KeySpan and ANP will
jointly own and operate two 250 MW electric generating  facilities to be located
on Long Island,  including the proposed  Melville  facility.  The joint proposal
also recommends that between 80% to 100% of the capacity of these two facilities
be sold to LIPA under  long-term  power purchase  agreements.  It is anticipated
that LIPA will respond to the joint proposal in the fourth quarter of 2003.


                                       46
<PAGE>

As part of our growth strategy, we continually evaluate the possible acquisition
and development of additional generating  facilities in the Northeast.  However,
we are unable to predict when or if any such facilities will be acquired and the
effect  any such  acquired  facilities  will  have on our  financial  condition,
results of operations or cash flows.

Energy Services

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

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

<TABLE>
<CAPTION>

--------------------------------------------------------------------------------------------------------------------------
                                                             Three Months Ended                    Nine Months Ended
                                                                September 30,                         September 30,
(In Thousands of Dollars)                             2003                2002                    2003             2002
--------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>                <C>                   <C>                <C>
Revenues                                            $ 150,802          $ 217,104             $ 500,163          $ 687,975
Less: cost of gas and fuel                              7,731             45,809                86,572            157,694
--------------------------------------------------------------------------------------------------------------------------
Net Revenues                                          143,071            171,295               413,591            530,281
Other operating expenses                              156,698            176,129               446,238            555,337
--------------------------------------------------------------------------------------------------------------------------
Operating (Loss) Income                             $ (13,627)          $ (4,834)            $ (32,647)         $ (25,056)
--------------------------------------------------------------------------------------------------------------------------
</TABLE>


Revenues decreased approximately 31% and 27% for the three and nine months ended
September 30, 2003,  respectively,  compared to the same periods last year, due,
in part, to lower revenues realized by the Business Solutions group of companies
as a result of the  softness in the  construction  industry in the  northeastern
United States, as well as from the  discontinuation  of the general  contracting
business of one of our subsidiaries.  The Business  Solutions group of companies
provide mechanical,  contracting, plumbing, engineering, and consulting services
to commercial, institutional, and industrial customers. Further, on May 1, 2003,
KeySpan's  gas and  electric  marketing  subsidiary,  KeySpan  Energy  Services,
assigned the majority of its retail natural gas customers,  consisting mostly of
residential  and small  commercial  customers,  to  ECONnergy  Energy Co.,  Inc.
("ECONnergy).  KeySpan Energy  Services  continues to provide retail natural gas
marketing to a small number of customers in New Jersey and plans to continue its
electric marketing  activities.  Comparative  revenues,  as well as gas and fuel
costs were impacted by this transaction.


                                       47
<PAGE>

Operating  Income for the Business  Solutions  group of  companies  decreased by
$11.6  million for the third  quarter of 2003 and by $22.3  million for the nine
months ended  September  30, 2003,  compared to the  corresponding  periods last
year. These declines reflect the softness in the  construction  industry,  which
has delayed the start-up of certain engineering and construction  projects,  and
has generally increased  competition for remaining  opportunities.  As a result,
the  Business  Solution  group of  companies  have  realized  lower  margins  on
construction  projects  currently  in progress.  This is further  reflected by a
backlog of  approximately  $527  million at September  30, 2003 (which  includes
backlog of $38 million  purchased in a recent  acquisition as discussed  below),
compared to $514 million at December 31, 2002 and $578 million at September  30,
2002.

Offsetting,  in part, the results of the Business  Solutions group of companies,
were  comparative  increases  in  operating  earnings of $2.8  million and $14.7
million for the three and nine months ended  September  30, 2003,  respectively,
associated  with the Home Energy  Services group of companies.  These  companies
provide residential and small commercial  customers with service and maintenance
contracts,  as well as the  retail  marketing  of natural  gas and  electricity.
Comparative  operating  income  reflects  losses incurred during the nine months
ended September 30, 2002,  resulting from the  non-renewal of appliance  service
contracts  due to the  warm  first  quarter  2002  weather,  as  well as from an
increase in the provision for bad debts.

Other Matters

During the third quarter of 2003, KeySpan Services,  Inc., and its wholly- owned
subsidiary,  Paulus,  Sokolowski and Sartor,  LLC., acquired Bard, Rao + Athanas
Consulting  Engineers,  Inc.  (BR+A),  a  company  engaged  in the  business  of
providing  engineering services relating to mechanical,  electrical and plumbing
systems.  The  purchase  price  was $35  million,  plus up to $14.7  million  in
contingent consideration depending on the financial performance of BR+A over the
five-year period after the closing of the acquisition. We have recorded goodwill
of $26  million  and  intangible  assets  of $2  million  associated  with  this
transaction.  The intangible assets,  which relate primarily to a portion of the
backlog purchased,  as well as to non-compete  agreements with all of the former
owners of BR+A, will be amortized over two and three years, respectively. We are
currently  in the  process of  evaluating  the fair  market  value of the assets
acquired and may adjust the recorded goodwill in the fourth quarter of 2003.

Energy Investments

The Energy  Investment  segment  consists of our gas  exploration and production
operations, certain other domestic and international energy-related investments,
as well as  certain  technology-related  investments.  Our gas  exploration  and
production  subsidiaries,   Houston  Exploration  and  KeySpan  Exploration  and
Production,  LLC  ("KES  E&P")  are  engaged  in gas  and  oil  exploration  and
production,  and the development and acquisition of domestic natural gas and oil
properties.  In line  with our  strategy  of  monetizing  or  divesting  certain
non-core  assets,  in October  2002 we  monetized a portion of our assets in the
joint venture  drilling  program with Houston  Exploration that was initiated in
1999.  Further,  in February 2003, we reduced our ownership  interest in Houston
Exploration  to  approximately  56% (from the previous level of 66%) through the
repurchase,  by Houston  Exploration,  of three  million  shares of common stock
owned by KeySpan.  The net  proceeds of  approximately  $79 million  received in


                                       48
<PAGE>

connection  with this  repurchase  were  used to pay down  short-term  debt.  We
realized a $19.0  million  gain on this  transaction  that was recorded in Other
Income and Deductions in the Consolidated Statement of Income. Income taxes were
not provided on this  transaction,  since the  transaction  was  structured as a
return of capital.

On October 15,  2003,  Houston  Exploration  acquired  the entire Gulf of Mexico
shallow-water asset base of Transworld Exploration and Production, Inc. for $149
million.  The  properties,  which are 75% natural gas,  have proven  reserves of
approximately  92  billion  cubic  feet  of  natural  gas  equivalent.   Current
production  is from 11 fields and is producing  approximately  35 million  cubic
feet  of  natural  gas  equivalent  per  day.  Houston  Exploration  funded  the
transaction from its bank revolver and from cash on hand at the time of closing.
Consistent with past  acquisitions,  Houston  Exploration  has derivative  hedge
positions in place for a portion of the 2004 production.


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

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                                                             Three Months Ended                          Nine Months Ended
                                                                September 30,                              September 30,
(In Thousands of Dollars)                                 2003               2002                     2003              2002
------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>                <C>                     <C>              <C>
Revenues                                                $ 123,052          $ 88,600                $ 373,774        $ 256,089
Depletion and amortization expense                         48,641            44,880                  145,559          130,766
Other operating expenses                                   23,416            17,366                   71,482           49,690
------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------
Operating Income                                         $ 50,995          $ 26,354                $ 156,733         $ 75,633
------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------
Natural gas and oil production (Mmcf)                      26,984            26,914                   80,188           79,641
Natural gas (per Mcf) realized                           $   4.45          $   3.23                $    4.64         $   3.17
Natural gas (per Mcf) unhedged                           $   4.84          $   3.09                $    5.45         $   2.89
------------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

The  increase in  operating  income of $24.6  million and $81.1  million for the
three and nine months ended  September 30, 2003,  compared to the  corresponding
periods  last year,  reflects a  significant  increase in  revenues.  The higher
revenues  were  offset,  to some extent,  by an increase in  operating  expenses
associated  with a higher  depletion  rate, as well as greater  lease  operating
expenses, as discussed below. Revenues for both the third quarter and first nine
months of 2003 benefited  from  increases of 38% and 46% in comparative  average
realized gas prices  (average  wellhead price received for production  including
hedging gains and losses).

Derivative  financial hedging instruments are employed by Houston Exploration to
provide  more  predictable  cash  flow,  as well as to reduce  its  exposure  to
fluctuations in natural gas prices. The average realized gas price for the third
quarter of 2003 was 92% of the average unhedged natural gas price,  resulting in
revenues  that were $9.7  million  lower  than  revenues  that  would  have been
achieved if derivative  financial  instruments  had not been in place during the
second quarter of 2003. The average realized gas price for the nine months ended
September 30, 2003 was 85% of the average unhedged natural gas price,  resulting
in revenues  that were $59.7  million  lower than  revenues that would have been
realized if derivative  financial  instruments  had not been in place during the
first nine months of 2003. Houston  Exploration hedged slightly less than 70% of
its 2003 third quarter and nine months production,  principally  through the use
of costless collars, and a similar amount for its 2004 production.


                                       49
<PAGE>

The  average  realized  gas price for the third  quarter of 2002 was 105% of the
average  unhedged natural gas price resulting in revenues that were $3.5 million
higher  than  revenues  that would have been  realized if  derivative  financial
instruments  had not been employed  during the third  quarter 2002.  The average
realized gas price for the nine months ended  September 30, 2002 was 110% of the
average unhedged natural gas price resulting in revenues that were $20.5 million
higher  than  revenues  that would have been  realized if  derivative  financial
instruments  had not been  employed  during the first nine months of 2002.  (See
Note  6 to  the  Consolidated  Financial  Statements,  "Hedging  and  Derivative
Financial Instruments" for further information on these derivative positions.)


The  depletion  rate for the nine months ended  September 30, 2003 was $1.80 per
Mcf , compared to $1.64 per Mcf for the same period in 2002.  The depletion rate
has  increased  as  Houston  Exploration  completed  the  evaluation  of several
properties  that were  classified as unproved during the fourth quarter of 2002.
As the evaluation is completed,  the costs  associated with these properties are
reclassified into the amortization base without  incremental  reserve additions.
In addition, future development costs have increased from prior year estimates.

The  increase  in other  operating  expenses  for both the three and nine months
ended  September 30, 2003,  compared to same periods last year was primarily due
to increased lease operating costs and severance taxes. Lease operating expenses
increased  $1.5  million and $9.5  million  for the three and nine months  ended
September  30, 2003,  respectively,  as a result of the  continued  expansion of
operations  both onshore and  offshore.  Severance  tax,  which is a function of
volume and revenues  generated from onshore  production,  increased $0.7 million
and $3.7  million  for the three  and nine  months  ended  September  30,  2003,
respectively, as a result of the increase in average wellhead prices for natural
gas. Overall  operating  expenses are increasing as new wells and facilities are
added and production from existing wells is maintained.

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

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

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


                                       50
<PAGE>

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>
--------------------------------------------------------------------------------------------------------------------------
                                                           Three Months Ended                       Nine Months Ended
                                                             September 30,                             September 30,
(In Thousands of Dollars)                              2003               2002                    2003              2002
--------------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>               <C>                     <C>              <C>
Revenues                                              $ 27,699          $ 23,793                $ 84,043         $ 63,366
Operation and maintenance expense                       16,709            10,849                  52,743           44,675
Other operating expenses                                 5,708             4,699                  16,471           13,271
Equity earnings                                          2,727             2,281                  12,378            9,661
--------------------------------------------------------------------------------------------------------------------------
Operating Income                                      $  8,009          $ 10,526                $ 27,207         $ 15,081
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

*Operating income above reflects 100% of KeySpan Canada's results.


The increase in operating  income for the nine months ended  September  30, 2003
compared to the same period last year reflects, in part, higher operating income
associated with our Canadian  investments,  primarily KeySpan Canada, as well as
higher  earnings  from  our  Northern   Ireland   investments.   KeySpan  Canada
experienced  higher unit sales, as well as higher quantities of sales of natural
gas  liquids in 2003,  as a result of  increasing  oil  prices.  The  pricing of
natural gas liquids is directly related to oil prices. Operating income for 2003
also reflects our  investment in KeySpan LNG storage  facility  located in Rhode
Island, which we acquired in December 2002.

KeySpan has  announced a joint  initiative  with BG LNG  Services to upgrade the
storage  and  receiving  terminal  at the  KeySpan's  LNG  facility  located  in
Providence,  Rhode Island.  Pending  approvals,  the facility  could be ready to
accept  marine  deliveries  by 2005.  We  anticipate  making  an  investment  of
approximately $50 million to upgrade the facility.

We do not  consider  certain  businesses  contained  in the  Energy  Investments
segment to be part of our core asset  group.  We have stated in the past that we
may sell or  otherwise  dispose of all or a portion of our non-core  assets.  As
previously indicated, in May 2003 we monetized 39.09% of our interest in KeySpan
Canada, a company with natural gas processing plants and gathering facilities in
Western  Canada.  These  assets  include 14  processing  plants  and  associated
gathering  systems that can process  approximately 1.5 BCFe of natural gas daily
and provide associated natural gas liquids  fractionation.  We sold a portion of
our interest in KeySpan Canada through the establishment of an open-ended income
fund trust (the "Fund")  organized under the laws of Alberta,  Canada.  The Fund
acquired the 39.09%  ownership  interest of KeySpan  Canada  through an indirect
subsidiary,  and then  issued 17 million  trust  units to the public  through an
initial public offering. Each trust unit represents a beneficial interest in the
Fund and is registered on the Toronto Stock Exchange (KEY.UN).  Additionally, we
sold our 20%  interest in Taylor NGL LP that owns and  operates  two  extraction
plants also in Canada to AltaGas  Services,  Inc. We received  cash  proceeds of
$119.4 million associated with these transactions and recorded a pre-tax loss of
$30.3 million ($34.1 million after-tax).


                                       51
<PAGE>

Based on current  market  conditions  we cannot  predict  when, or if, any other
sales or  dispositions of our non-core assets may take place, or the effect that
any such sale or  disposition  may have on our  financial  position,  results of
operations or cash flows.

 Allocated Costs

KeySpan  is  subject to the  jurisdiction  of the SEC under the  Public  Utility
Holding  Company Act ("PUHCA").  As part of the regulatory  provisions of PUHCA,
the SEC regulates various transactions among affiliates within a holding company
system.  In accordance with the SEC's  regulations  under PUHCA and the New York
State  Public  Service  Commission  ("NYPSC")  requirements,   we  have  service
companies that provide: (i) traditional  corporate and administrative  services;
(ii) gas and electric transmission and distribution systems planning, marketing,
and gas supply  planning and  procurement;  and (iii)  engineering and surveying
services to  subsidiaries.  As required by the SEC,  during the third quarter of
2003,  we adjusted  certain  provisions  in our  allocation  methodology.  These
adjustments  have resulted in a higher level of costs remaining at our corporate
holding company level than in the past.

Liquidity

Cash flow from operations for the nine months ended September 30, 2003 decreased
$18.3  million,  or 2%,  compared to the same period last year,  due in part, to
higher pension and other postretirement funding requirements. Although KeySpan's
funding  balance is currently in excess of ERISA minimum  funding  requirements,
our pension plans, on an actuarial basis, are currently underfunded. In order to
limit future funding  requirements,  we follow a multi-year funding strategy. As
such, we contributed approximately $90 million to KeySpan's pension plans during
the nine months ended  September  30,  2003.  In addition,  we  contributed  $35
million in other postretirement funding. For the nine months ended September 30,
2002,  pension and other post retirement  funding amounted to approximately  $40
million.  (See Critical Accounting  Policies and Assumptions  "Pension and Other
Postretirement  Benefits" for a further  discussion of these matters.)  Further,
higher  natural gas prices  during the nine months  ended  September  30,  2003,
compared  to the same period last year  resulted  in  significantly  higher cash
expenditures required to re-fill natural gas storage levels.

Offsetting, to a large degree, these adverse impacts to operating cash flow, was
an  increase  in  comparative  operating  cash flow from the  collection  of gas
accounts  receivable  associated  with winter gas heating sales.  As a result of
load  additions,  colder  than normal  winter  weather,  and higher  natural gas
prices, cash receipts from the prior winter heating sales were higher during the
nine  months  ended  September  30,  2003  compared  to the same period in 2002.
Further, the higher natural gas prices resulted in an increase in operating cash
flow associated with the operations of Houston Exploration.

During   2003,   KeySpan   performed  an  analysis  of  costs   capitalized   to
self-constructed property and inventory for income tax purposes. Keyspan filed a
change of  accounting  method for income tax purposes  resulting in a cumulative
deduction  for costs  previously  capitalized.  As a result  of this tax  method
change,  along with accelerated  deductions  resulting from bonus  depreciation,
Keyspan generated a net operating loss on its 2002 tax return. Consequently,  in
October  2003,  we received a $192.3  million  refund from the Internal  Revenue
Service associated with the refund of prior year taxes. We anticipate  receiving
an additional refund of $40 million in early 2004.


                                       52
<PAGE>

At September  30, 2003,  we had cash and temporary  cash  investments  of $118.1
million.  During the nine months  ended  September  30, 2003,  we repaid  $271.3
million of  commercial  paper and, at  September  30,  2003,  $644.4  million of
commercial paper was outstanding at a weighted average annualized  interest rate
of 1.15%.  We had the ability to borrow up to an  additional  $655.6  million at
September 30, 2003, under the terms of our credit facility.

In June 2003, KeySpan renewed its $1.3 billion revolving credit facility,  which
was syndicated  among sixteen banks.  The facility is used to support  KeySpan's
commercial  paper program,  and consists of two separate credit  facilities with
different  maturities but  substantially  similar terms and  conditions:  a $450
million  facility that extends for 364 days, and a $850 million facility that is
committed  for  three  years.  The  fees for the  facilities  are  subject  to a
ratings-based  grid,  with an annual fee that  ranges  from eight to twenty five
basis  points on the  364-day  facility  and ten to twenty  basis  points on the
three-year  facility.  Both credit  agreements allow for KeySpan to borrow using
several different types of loans;  specifically,  Eurodollar  loans,  Adjustable
Bank Rate (ABR) loans, or competitively bid loans. Eurodollar loans are based on
the  Eurodollar  rate plus a margin.  ABR loans are based on the  highest of the
Prime Rate,  the base CD rate plus 1%, or the Federal Funds  Effective Rate plus
0.5%, plus a margin. Competitive bid loans are based on bid results requested by
KeySpan from the lenders.  The margins on both  facilities are ratings based and
range from zero basis points to 112.5 basis points. The margins are increased if
outstanding loans are in excess of 33% of the total facility.  In addition,  the
364-day facility has a one-year term out option,  which would cost an additional
0.25%  if  utilized.  We do not  anticipate  borrowing  against  this  facility;
however,  if the  credit  rating  on our  commercial  paper  program  were to be
downgraded, it may be necessary to do so.

The  credit  facility  contains  certain   affirmative  and  negative  operating
covenants,  including  restrictions  on KeySpan's  ability to mortgage,  pledge,
encumber  or  otherwise  subject its  property  to any lien,  as well as certain
financial  covenants  that  require  us  to,  among  other  things,  maintain  a
consolidated  indebtedness to consolidated  capitalization ratio of no more than
64%.  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.

Under the terms of the credit facility,  KeySpan's debt-to-total  capitalization
ratio  reflects  80% equity  treatment  for the MEDS Equity  Units issued in May
2002. In addition,  the $425 million Ravenswood Master Lease is treated as debt.
At September 30, 2003, consolidated indebtedness,  as calculated under the terms
of the  credit  facility  was  58.4% of  consolidated  capitalization.  (See the
discussion  under  "Off-Balance  Sheet  Arrangements"  for an explanation of the
Ravenswood Master Lease.)

The  credit  facility  also  requires  that net cash  proceeds  from the sale of
significant  subsidiaries  be  applied  to  reduce  consolidated   indebtedness.
Further,  an acceleration of indebtedness of KeySpan or one of its  subsidiaries
for borrowed  money in excess of $25 million in the  aggregate,  if not annulled


                                       53
<PAGE>

within 30 days after written notice,  would create an event of default under the
Indenture  dated  November  1,  2000,   between  KeySpan   Corporation  and  the
JPMorganChase Bank as Trustee.  At September 30, 2003, KeySpan was in compliance
with all covenants.

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

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

Financial  covenants  require Houston  Exploration  to, among other things,  (i)
maintain an interest  coverage ratio of at least 3.00 to 1.00 of earnings before
interest,  taxes and depreciation  ("EBITDA") to cash interest;  (ii) maintain a
total debt to EBITDA  ratio of not more than 3.50 to 1.00;  and (iii)  generally
prohibits the hedging of more than 70% of natural gas and oil production  during
any  12-month  period.  At  September  30,  2003,  Houston  Exploration  was  in
compliance with all financial covenants.

During the nine months ended September 30, 2003,  Houston  Exploration  borrowed
$71 million under its credit facility and repaid $223 million.  At September 30,
2003,  Houston  Exploration  had no  outstanding  borrowings  under  its  credit
facility.  However,  $0.4 million was  committed  under  outstanding  letters of
credit  obligations  and $299.6  million of borrowing  capacity  was  available.
Subsequent  to September  30, 2003,  Houston  Exploration  borrowed $115 million
under  this  credit  facility  to fund a portion of the  purchase  price for the
producing  properties acquired from Transworld  Exploration and Production Inc.,
as previously mentioned.

In June 2003, KeySpan Canada replaced its two outstanding credit facilities with
one new facility with three  tranches that combined  allowed  KeySpan  Canada to
borrow up to  approximately  $125  million.  At the time of the partial  sale of
KeySpan Canada,  net proceeds from the sale of $119.4 million plus an additional
$45.7  million  drawn  under  the new  credit  facilities  were used to pay down
existing  outstanding debt of $160.4 million.  Then, during the third quarter of
2003, KeySpan Canada issued Cdn$125 million,  or approximately US$93 million, in
long-term  secured  notes in a private  placement.  The proceeds of the offering
were used to pay-down, in its entirety,  outstanding borrowings under the credit
facility.  Further,  one tranch of the credit  facility was  discontinued.  (See
"Financing"  below  for  further   information   regarding  the  long-term  debt
issuance.)  At September  30, 2003,  KeySpan  Canada's  credit  facility has the
following two tranches with the following maturities:  (i) $37.5 million matures
in 364 days:  and (ii) $37.5 million  matures in two years.  For the nine months


                                       54
<PAGE>

ended  September 30, 2003,  KeySpan Canada borrowed $71.5 million from its prior
credit facilities and repaid $240.2 million. At September 30, 2003, there are no
outstanding  borrowings under the credit facility,  and $75 million is available
for future borrowing. KeySpan is not a guarantor of this facility.

In September  2003,  the Boston Gas Company  redeemed all 562,700  shares of its
outstanding Variable Term Cumulative Preferred Stock, 6.42 % Series A at its par
value of $25 per share.  The total payment was $14.3 million which included $0.2
million of accumulated dividends. This preferred stock series had been reflected
as Minority Interest on KeySpan's Consolidated Balance Sheet.

On January 17, 2003,  KeySpan  sold 13.9  million  shares of common stock on the
open market and realized net proceeds of approximately $473 million.  All shares
were offered by KeySpan pursuant to the effective shelf  registration  statement
filed  with the SEC.  Net  proceeds  from the  equity  sale  were used to call a
portion  of  outstanding  promissory  notes to LIPA as is further  explained  in
"Capital Expenditures and Financing" below. In addition, as previously noted, we
used the net proceeds of approximately  $79 million received in February 2003 in
connection  with  the  partial  monetization  of  Houston  Exploration  to repay
short-term debt.

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.

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

Capital Expenditures and Financing

Construction Expenditures

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

------------------------------------------------------------------------------
                                             Nine Months Ended September 30,
(In Thousands of Dollars)                       2003                    2002
------------------------------------------------------------------------------
Gas Distribution                            $ 274,702               $ 294,774
Electric Services                             200,425                 290,790
Energy Investments                            235,322                 216,157
Energy Services and other                       9,768                  13,434
------------------------------------------------------------------------------
                                            $ 720,217               $ 815,155
------------------------------------------------------------------------------


                                       55
<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  new  Long  Island  generating
facilities as previously noted. The decrease in Electric  Services  construction
expenditures for the nine months ended September 30, 2003,  compared to the same
period last year  reflects the fact that  construction  of the Glenwood and Port
Jefferson  peaking  facilities  was  substantially  completed  by June 30, 2002.
Construction  expenditures  related to the Energy Investments  segment primarily
reflect costs associated with gas exploration and production  activities.  These
costs are related to the exploration and development of properties  primarily in
Southern  Louisiana  and  in the  Gulf  of  Mexico.  Expenditures  also  include
development costs associated with the joint venture with Houston Exploration, as
well as costs related to KeySpan Canada's gas processing facilities.

At September 30, 2003, total expenditures associated with the siting, permitting
and construction of the Ravenswood expansion project, the siting, permitting and
procurement  of equipment for the Long Island 250MW  combined  cycle  generation
plant,  and the siting and permitting of the Islander East pipeline project were
$338 million.

Financing

During the third quarter of 2003,  KeySpan Canada,  issued Cdn$125  million,  or
approximately  US$93 million,  long-term secured notes in a private placement to
investors  in  Canada  and the  United  States.  The  notes  were  issued in the
following three series:  (i) Cdn$20 million 5.42% senior secured notes due 2008;
(ii) Cdn$52.5  million 5.79% senior  secured notes due 2010;  and (iii) Cdn$52.5
million 6.16% senior  secured notes due 2013.  The proceeds of the offering have
been used to re-pay KeySpan Canada's credit facility.

In June 2003,  Houston  Exploration  closed on a private placement issue of $175
million of 7.0%,  senior  subordinated  notes due 2013.  Interest  payments will
begin on December 15, 2003, and will be paid semi-annually thereafter. The notes
will mature on June 15, 2013.  Houston  Exploration  has the right to redeem the
notes as of June 15, 2008,  at a price equal to the issue price plus a specified
redemption premium.  Until June 15, 2006, Houston Exploration may also redeem up
to 35% of the notes at a redemption  price of 107% with  proceeds from an equity
offering.  Houston  Exploration  incurred  approximately  $4.5  million  of debt
issuance costs on this private placement. In July 2003, Houston Exploration used
a portion of the net proceeds from the issuance to redeem all of its outstanding
$100 million principal amount of 8.625% senior  subordinated notes due 2008 at a
price of 104.313% of par plus  interest  accrued to the  redemption  date.  Debt
redemption costs totaled  approximately $5.9 million. The remaining net proceeds
from the  offering  were used to reduce debt  amounts  associated  with  Houston
Exploration's bank revolving credit facility.

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


                                       56
<PAGE>

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

KeySpan had authorization  under PUHCA to issue up to $2.2 billion of securities
through December 31, 2003. Following the recent common stock offering previously
mentioned and shares of common stock expected to be issued for employee  benefit
and dividend  reinvestment  plans,  we have  generally  exhausted our ability to
issue new  securities  under  our  current  PUHCA  authorization.  However,  the
issuance of securities in connection with the redemption of existing  securities
(including the promissory  notes  discussed  previously) is permitted  under our
PUHCA  authorization  notwithstanding  the  foregoing  limit.  We have  filed an
application with the SEC requesting  authorization to, among other things, issue
up to an additional $3 billion of  securities  through  December 31, 2006. It is
anticipated that this authorization will be obtained before the end of the year.
This request is intended to provide us with the necessary flexibility to finance
our future capital requirements over the next three years.

During the remainder of 2003, we intend to issue  approximately  $150 million of
either taxable or tax-exempt  long-term debt securities in a manner that will be
exempt  from  PUHCA  restrictions.  We  anticipate  that the  proceeds  from the
issuance  will be used to re-pay  outstanding  commercial  paper  related to the
construction of the two Long Island peaking-power plants that became operational
in 2002.  In addition  we  anticipate  replacing  outstanding  commercial  paper
related to the construction of the 250 MW combined cycle generating  facility at
the Ravenswood  facility site with permanent  financing by the end of the second
quarter  of 2004.  We will  continue  to  evaluate  our  capital  structure  and
financing  strategy for 2003 and beyond.  We believe that our current sources of
funding (i.e., internally generated funds, the issuance of additional securities
as noted above, and the availability of commercial paper) are sufficient to meet
our anticipated capital needs for the foreseeable future.

The following  table  represents  the ratings of our long-term debt at September
30, 2003. Currently,  these ratings are all on stable outlook with the exception
of Standard & Poor's ratings on KeySpan's and its subsidiaries'  long-term debt,
which are on negative outlook.


                                       57
<PAGE>

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
                                  Moody's Investor            Standard
                                      Services                & Poor's            FitchRatings
----------------------------------------------------------------------------------------------------
<S>                                    <C>                      <C>                  <C>
KeySpan Corporation                      A3                      A                    A-
KEDNY                                   N/A                      A+                   A+
KEDLI                                    A2                      A+                   A-
Boston Gas                               A2                      A                    N/A
Colonial Gas                             A2                      A+                   N/A
Electric Generation                      A3                      A                    N/A
----------------------------------------------------------------------------------------------------
</TABLE>


Off-Balance Sheet Arrangements

Guarantees

KeySpan has a number of  financial  guarantees  for its  subsidiaries  that have
remained substantially unchanged since December 31, 2002. At September 30, 2003,
KeySpan  has fully and  unconditionally  guaranteed  certain  medium-term  notes
issued by KEDLI. The medium-term notes are reflected on the Consolidated Balance
Sheet. Further, KeySpan has guaranteed: (i) surety bonds associated with certain
construction  projects  currently  being  performed by  subsidiaries  within the
Energy  Services  segment;  (ii) certain supply  contracts,  margin accounts and
purchase orders for certain  subsidiaries,  as well as an unaffiliated  company;
(iii) the  obligations  of KeySpan  Ravenswood  LLC,  the lessee  under the $425
million Master Lease Agreement associated with the Ravenswood facility; and (iv)
certain subsidiary letters of credit.  KeySpan had also guaranteed a $25 million
line of  credit  for  Hawkeye  Electric,  LLC,  and  Hawkeye  Construction,  LLC
(collectively  "Hawkeye"),  a  non-affiliated  company.  As part of a settlement
agreement  with  Hawkeye,  KeySpan's  guarantee  of such line of credit has been
terminated. These guarantees are not recorded on the Consolidated Balance Sheet.
At this time, we have no reason to believe that our subsidiaries will default on
their current  obligations.  However,  we cannot predict when or if any defaults
may take place or the impact such defaults may have on our consolidated  results
of  operations,   financial  condition  or  cash  flows.  (See  Note  8  to  the
Consolidated Financial Statements,  "Financial Guarantees and Contingencies" and
Note 9 "Variable Interest Entity" for additional information regarding KeySpan's
guarantees  and a description  of the leasing  arrangement  associated  with the
Ravenswood Master Lease Agreement.)

Variable Interest Entity

We have an arrangement with a variable  interest entity through which we lease a
portion of the  Ravenswood  facility.  We acquired the Ravenswood  facility,  in
part, through the variable interest entity from The Consolidated  Edison Company
of New York  ("Consolidated  Edison")  on June 18, 1999 for  approximately  $597
million.  In order to reduce the initial  cash  requirements,  we entered into a
lease  agreement  (the "Master  Lease") with a variable  interest,  unaffiliated
financing entity that acquired a portion of the facility, three steam generating
units,  directly from Consolidated Edison and leased it to a KeySpan subsidiary.
The variable  interest  unaffiliated  financing entity acquired the property for
$425 million,  financed with debt of $412.3 million (97% of capitalization)  and
equity of $12.7 million (3% of capitalization). Monthly lease payments equal the
monthly  interest  expense on the debt  securities.  The Master Lease  currently
qualifies  as  an  operating  lease  for  financial   reporting  purposes  while
preserving  our  ownership  of the  facility  for federal  and state  income tax
purposes.


                                       58
<PAGE>

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

Contractual Obligations

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

Discussions of Critical Accounting Policies and Assumptions

In preparing our financial  statements,  the  application of certain  accounting
policies  requires   difficult,   subjective  and/or  complex   judgments.   The
circumstances  that make these judgments  difficult,  subjective  and/or complex
have to do with the need to make estimates  about the impact of matters that are
inherently  uncertain.  Actual effects on our financial  position and results of
operations  may vary  significantly  from expected  results if the judgments and
assumptions  underlying the estimates  prove to be inaccurate.  At September 30,
2003,  KeySpan's  critical  accounting  policies and  assumptions  have remained


                                       59
<PAGE>

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

Percentage of Completion Accounting

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

Valuation of Goodwill

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

KeySpan currently has $1.8 billion of recorded  goodwill;  the majority of which
is recorded in the Gas Distribution and Energy  Investments  segment,  with $169
million recorded in the Energy Services segment. As permitted under SFAS 142, we
can rely on our previous  valuations for the annual impairment  testing provided
that the following  criteria for each reporting unit are met: (a) the assets and
liabilities that make up the reporting unit have not changed significantly since
the most  recent  fair value  determination;  and (b) the most recent fair value
determination  resulted in an amount that  exceeded the  carrying  amount of the
reporting unit by a substantial margin and there is no economic  indication that
the carrying value of goodwill may be impaired.

In the case of the Gas  Distribution  and the Energy  Investments  segment,  the
above criteria have been met and no further evaluation is required. In regard to
the  Energy  Services  segment,  criteria  (b) was not met since the fair  value
valuation  performed  last year did not exceed the  carrying  value by an amount
deemed by us to be substantial. As a result, we will be conducting an impairment
test during the fourth quarter of 2003.


                                       60
<PAGE>

Accounting for the Effects of Rate Regulation on Gas Distribution Operations

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

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

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  ten-year  periods  ending  2008 and 2009,  respectively.  Due to the
length of these base rate  freezes,  the  Colonial and Essex Gas  Companies  had
previously   discontinued  the  application  of  SFAS  71.  Rate  regulation  is
undergoing  significant change as regulators and customers seek lower prices for
utility service and greater  competition among energy service providers.  In the
event that  regulation  significantly  changes the opportunity for us to recover
costs in the future, all or a portion of our regulated  operations may no longer
meet the criteria for the application of SFAS 71. In that event, a write-down of
our existing  regulatory  assets and liabilities  could result.  In management's
opinion, our regulated subsidiaries that currently are subject to the provisions
of SFAS 71 will continue to be subject to SFAS 71 for the foreseeable future.

As is further  discussed  under the caption  "Regulation  and Rate Matters," the
rate plans previously in effect for KEDNY, KEDLI and Boston Gas Company have all
expired. The continued  application of SFAS 71 to record the activities of these
subsidiaries  is contingent upon the actions of regulators with regard to future
rate  plans.  We filed a base rate case and a  performance  based  rate plan for
Boston Gas Company on April 16, 2003. On October 31, 2003,  the DTE rendered its
decision on the rate  proposal and allowed for,  among other  things,  continued
application of SFAS 71.  Further,  we are currently  evaluating  various options
that may be available to us  including,  but not limited to,  proposing new rate
plans for KEDNY and KEDLI.  The  ultimate  resolution  of any future  rate plans
could have a significant  impact on the application of SFAS 71 to these entities
and,  accordingly,  on our financial  position,  results of operations  and cash
flows.  However,  management believes that currently available facts support the
continued  application of SFAS 71 and that all regulatory assets and liabilities
are recoverable or refundable through the regulatory environment.

Pension and Other Postretirement Benefits

KeySpan participates in both non-contributory  defined benefit pension plans, as
well   as   other   post-retirement   benefit   ("OPEB")   plans   (collectively
"postretirement plans").  KeySpan's reported costs of providing pension and OPEB
benefits  are  dependent  upon  numerous  factors  resulting  from  actual  plan
experience  and  assumptions  of  future  experience.  Pension  and  OPEB  costs
(collectively   "postretirement   costs")  are   impacted  by  actual   employee


                                       61
<PAGE>

demographics,  the level of  contributions  made to the plans,  earnings on plan
assets,  and health care cost trends.  Changes made to the  provisions  of these
plans may also impact current and future  postretirement  costs.  Postretirement
costs  may  also  be   significantly   affected  by  changes  in  key  actuarial
assumptions,  including  anticipated  rates of  return  on plan  assets  and the
discount  rates  used  in  determining  the  postretirement  costs  and  benefit
obligations.

Historically,  we have funded our pension plans in excess of the amount required
to satisfy  minimum ERISA funding  requirements.  At December 31, 2002, we had a
funding  balance in excess of the ERISA minimum  funding  requirements  and as a
result KeySpan is not required to make any  contribution to its pension plans in
2003.  However,  although we presently  exceed ERISA funding  requirements,  our
pension plans, on an actuarial  basis,  are currently  underfunded.  In order to
limit future funding  requirements,  we follow a multi-year funding strategy. As
such, we contributed approximately $90 million to KeySpan's pension plans during
the nine months ended  September  30,  2003.  In addition,  we  contributed  $35
million in other postretirement funding. We will continue to monitor our funding
strategy,  and may elect to make  additional  contributions  during  the  fourth
quarter of 2003.  For the fiscal year ended  December  31,  2002 we  contributed
approximately $130 million to KeySpan's pension and other postretirement  plans.
(In  addition  to Item 7  Management's  Discussion  and  Analysis  of  Financial
Condition and Results of Operations in KeySpan's  Annual Report on Form 10-K for
the  Year  Ended  December  31,  2002,  see also  Note 4 to  those  Consolidated
Financial Statements, "Postretirement Benefits.")

Full Cost Accounting

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

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

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


                                       62
<PAGE>

Valuation of Derivative Instruments

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

When available, quoted market prices are used to record a contract's fair value.
However,  market  values for  certain  derivative  contracts  may not be readily
available  or  determinable.  A  number  of  our  commodity  related  derivative
instruments are exchange traded and,  accordingly,  fair value  measurements are
generally based on standard New York Mercantile  Exchange  ("NYMEX")  quotes. We
use  industry-published  indices,  NYMEX day-ahead  forward pricing,  as well as
other local published  indices to value  contracts for commodities  that are not
exchange traded, such as No. 6 grade fuel oil and electricity. The fair value of
our  electric  capacity  hedges  is based on  published  NYISO  day-ahead  award
pricing. Further, if no active market exists for a commodity, fair values may be
based on pricing models.  (See Note 6 to the Consolidated  Financial  Statements
"Hedging and Derivative Financial  Instruments" for a further description of all
our derivative instruments.)

Regulation and Rate Matters

Gas Matters

As of September 30, 2003, the rate  agreements  for KEDNY,  KEDLI and Boston Gas
Company  have  all  expired.  Under  the  terms  of the  KEDNY  and  KEDLI  rate
agreements,  gas  distribution  rates and all other  provisions  will  remain in
effect until changed by the NYPSC.  At this time,  we are  currently  evaluating
various  options that may be available to us regarding  the KEDNY and KEDLI rate
plans, including but not limited to, proposing new rate plans.

Regarding  the Boston  Gas  Company,  we filed a base rate case and  Performance
Based Rate Plan on April 16,  2003,  to be  effective  in the fourth  quarter of
2003.  On October 31,  2003,  the DTE  rendered  its  decision on the Boston Gas
Company's  proposal and approved a $26 million increase in base revenues with an
allowed  return on equity of 10.2% assuming an equal balance of debt and equity.
The DTE also approved a true-up  mechanism for pension and other  postretirement
benefit  costs  under  which   variations   between  actual  pension  and  other
postretirement  benefit  costs and amounts used to establish  rates are deferred
and  collected  from or refunded to customers in subsequent  periods  through an
adjustment  clause.  This  true-up  mechanism  allows  for  carrying  charges on
deferred assets and liabilities at Boston Gas Company's weighted-average cost of
capital.


                                       63
<PAGE>

The DTE also approved a  Performance  Based Rate Plan (the "Plan") for up to ten
years. The Plan allows for an annual revenue adjustment based on inflation, less
a .41 percent-productivity adjustment.

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

Electric Rate Matters

A  KeySpan  subsidiary  sells to LIPA all of the  capacity  and,  to the  extent
requested,  energy  conversion  services from our existing Long Island based oil
and  gas-fired  generating  plants.  Sales of  capacity  and  energy  conversion
services are made under rates  approved by the FERC.  The current FERC  approved
rates,  which have been in effect since May 1998,  are set to expire on December
31,  2003.  KeySpan  filed  with the FERC an  updated  cost of  service  for our
existing  Long Island based oil and gas-fired  generating  plants on October 31,
2003. The rate filing included,  among other things,  an annual revenue increase
of 2.1% or  approximately  $6.4  million,  a return on  equity  of 11%,  updated
operating and maintenance expense levels and recovery of certain other costs. It
is  anticipated  that the new rates  will be in effect  for a  five-year  period
beginning January 1, 2004.

Securities and Exchange Commission Regulation

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

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


                                       64
<PAGE>

order to manage and minimize  interest rate costs; (d) invest up to $2.2 billion
in  exempt  wholesale  generators;  and (e) pay  dividends  out of  capital  and
unearned   surplus  as  well  as   paid-in-capital   with   respect  to  certain
subsidiaries,  subject to certain  limitations.  In addition,  we have committed
that during the Authorization  Period, our common equity will be at least 30% of
our consolidated  capitalization  and each of our utility  subsidiaries'  common
equity will be at least 30% of such  entity's  capitalization.  At September 30,
2003,   our   consolidated   common   equity  was  39.6%  of  our   consolidated
capitalization,  including commercial paper and each of our utility subsidiaries
common equity was at least 35% of its respective  capitalization.  As previously
mentioned,  we have filed a new application  requesting  authorization to, among
other  things,  issue up to an  additional  $3  billion  of  securities  through
December 31, 2006. It is anticipated  that this  authorization  will be obtained
before the end of the year.

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  $173.3 million
and we have recorded a related  liability for such amount. We have also recorded
an additional $37.8 million liability  representing the estimated  environmental
cleanup costs related to a former coal tar processing  facility.  Further, as of
September 30, 2003,  we have expended a total of $92.5 million on  environmental
remediation.  (See Note 8 to the Consolidated  Financial Statements,  "Financial
Guarantees and Contingencies.")

Market and Credit Risk Management Activities

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

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


                                       65
<PAGE>

derivative contracts with energy marketing companies and financial institutions;
and the sale of gas, natural gas liquids,  oil and processing services to energy
marketing and oil and gas production companies.

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

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

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

Cautionary Statement Regarding Forward-Looking Statements

Certain  statements  contained in this Quarterly  Report on Form 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.


                                       66
<PAGE>

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

     -    volatility of energy 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;

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

     -    implementation of new accounting standards;

     -    inflationary trends and interest rates;

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

     -    available sources and cost of fuel;

     -    creditworthiness  of  counterparties  to  derivative  instruments  and
          commodity contracts;

     -    retention of key personnel;

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

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

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

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

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

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

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

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


                                       67
<PAGE>

     -    a change  in the fair  value of our  investments  that  could  cause a
          significant change in the carrying value of goodwill;

     -    timely  receipts of payments from our two largest  customers  LIPA and
          the NYISO; and

     -    other  risks  detailed  from time to time in other  reports  and other
          documents filed by KeySpan with the SEC.

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


Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Houston  Exploration has utilized collars and purchased put options,  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
September 30, 2003, Houston Exploration has hedged slightly less than 70% of its
estimated 2003 gas  production and a similar amount of its 2004 gas  production.
Houston Exploration used standard New York Mercantile Exchange ("NYMEX") futures
prices to value its swap positions,  and, in addition, used published volatility
in its Black-Scholes  calculation for outstanding options. The maximum length of
time over  which  Houston  Exploration  has  hedged  such  cash flow is  through
December 2004. The estimated  amount of losses  associated  with such derivative
instruments  that  are  reported  in  Other  Comprehensive  Income  and that are
expected to be  reclassified  into earnings over the next twelve months is $10.5
million, or $6.8 million after-tax.

With respect to price exposure associated with fuel purchases for the Ravenswood
facility,  KeySpan  employs  standard  NYMEX  natural gas futures  contracts and
over-the-counter  financially  settled natural gas basis swaps to hedge the cash
flow  variability for a portion of forecasted  purchases of natural gas. KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow variability for a portion of forecasted  purchases of fuel oil that will be
consumed at the  Ravenswood  facility.  The maximum length of time over which we
have  hedged cash flow  variability  associated  with  forecasted  purchases  of
natural  gas and fuel oil is through  September  2005.  We used  standard  NYMEX
futures  prices to value the gas futures  contracts  and industry  published oil
indices  for  number  6 grade  fuel oil to value  the oil  swap  contracts.  The
estimated amount of gains  associated with all such derivative  instruments that
are  reported  in  Other  Comprehensive  Income  and  that  are  expected  to be
reclassified into earnings over the next twelve months is $0.2 million,  or $0.1
million after-tax.


                                       68
<PAGE>

KeySpan Canada employs  natural gas swaps to lock-in a price for expected future
natural gas purchases.  As applicable,  we used 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 or losses associated with such derivative instruments that are reported
in Other  Comprehensive  Income and that are  expected to be  reclassified  into
earnings over the next twelve months is negligible at September 30, 2003.

We have also engaged in the use of  cash-settled  swap  instruments to hedge the
cash flow  variability  associated  with a portion of  forecasted  peak electric
energy  sales  from the  Ravenswood  facility,  as well as  forecasted  sales of
Unforced  Capacity  ("UCAP") to the NYISO. The maximum length of time over which
we have hedged cash flow  variability  is through  December  2004. We used NYMEX
day-ahead forward pricing,  as well as published NYISO day-ahead award prices to
value these outstanding  derivatives.  The estimated amount of losses associated
with such derivative instruments that are reported in Other Comprehensive Income
and that are  expected to be  reclassified  into  earnings  over the next twelve
months is $1.3 million, or $0.8 million after-tax.

KeySpan Canada also employs  electricity  swap contracts to lock-in the purchase
price  of  electricity  needed  to  operate  its gas  processing  plants.  These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $0.4 million, or $0.3 million after-tax.

The following  tables set forth selected  financial data  associated  with these
derivative financial  instruments noted above that were outstanding at September
30, 2003.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                   Year of    Volumes        Floor        Ceiling        Fixed Price      Current Price   Fair Value
        Type of Contract           Maturity    (mmcf)         ($)            ($)             ($)               ($)          ($000)
------------------------------------------------------------------------------------------------------------------------------------
             Gas
<S>                                 <C>        <C>        <C>           <C>             <C>               <C>              <C>
Collars                              2003       13,800            3.48          4.91                -      4.43 - 5.08       (4,085)
                                     2004       64,100     3.50 - 4.50   4.75 - 7.00                -      4.70 - 5.26       (7,757)

Put Options - Short Natural Gas      2004        9,100            5.00             -                -      5.11 - 5.26        4,228

Swaps/Futures - Short Natural Gas    2003        3,711               -             -             3.19      4.43 - 5.08       (5,842)
                                     2004       14,640               -             -             4.96      4.76 - 5.26        1,152

Swaps/Futures - Long Natural Gas     2004           50               -             -      5.11 - 5.14      4.71 - 4.72          (25)
                                     2005           10               -             -             4.95             4.46           (5)

------------------------------------------------------------------------------------------------------------------------------------
                                               105,411                                                                      (12,334)
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       69
<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
                                      Year of          Volumes         Fixed Price          Current Price       Fair Value
      Type of Contract                Maturity        (Barrels)             ($)                  ($)              ($000)
--------------------------------------------------------------------------------------------------------------------------
            Oil
<S>                                    <C>            <C>             <C>                  <C>                      <C>
Swaps - Long Fuel Oil                   2003            55,367         20.60 - 30.07        28.54 - 29.80             204
                                        2004           100,548         20.55 - 29.60        25.88 - 28.61              37
                                        2005            28,000         24.65 - 27.25        25.25 - 25.59             (31)
--------------------------------------------------------------------------------------------------------------------------
                                                       183,915                                                        210
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                                 Year of                                 Fixed Price          Current Price         Fair Value
      Type of Contract           Maturity      Capacity       MWh             ($)                  ($)                 ($000)
------------------------------------------------------------------------------------------------------------------------------
        Electricity
<S>                               <C>            <C>        <C>         <C>                  <C>                     <C>
Swaps - Energy                     2003                      222,464     15.00 - 67.44        15.90 - 42.98             (613)
                                   2004                      340,800     14.00 - 26.50        17.15 - 41.96             (953)

Swaps - Capacity                   2003           100                             7.00                 6.98                2
                                   2004           200                             7.00                 6.98                4

------------------------------------------------------------------------------------------------------------------------------
                                                  300        563,264                                                  (1,560)
------------------------------------------------------------------------------------------------------------------------------
</TABLE>


-------------------------------------------------------------------------------
(In Thousands of Dollars)                                                2003
Change in Fair Value of Derivative Hedging Instruments                  ($000)
-------------------------------------------------------------------------------
Fair value of contracts at January 1,                                $ (32,628)
Net losses on contracts realized                                        30,157
(Decrease) in fair value of all open contracts                         (11,213)
-------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30,                 $ (13,684)
-------------------------------------------------------------------------------

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
-------------------------------------------------------------------------------------------------------
                                                      Fair Value of Contracts
-------------------------------------------------------------------------------------------------------
                                                     Maturity             Maturity              Total
Sources of Fair Value                              In 12 Months         Through 2005         Fair Value
-------------------------------------------------------------------------------------------------------
<S>                                                 <C>                    <C>                <C>
Prices actively quoted                             $  (9,251)             $   (215)          $  (9,466)
Prices provided by external sources                       (5)                    -                  (5)
Prices based on models and
    other valuation methods                           (1,223)               (1,636)             (2,859)
Local published indicies                              (1,413)                   59              (1,354)
-------------------------------------------------------------------------------------------------------
                                                   $ (11,892)             $ (1,792)          $ (13,684)
-------------------------------------------------------------------------------------------------------
</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 swap  transactions  for  natural gas  liquids.  Such  contracts  are
executed  by KeySpan  Canada to: (i) 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 to  counterparties.
These derivative financial instruments do not qualify for hedge accounting under
SFAS 133,  "Accounting for Derivative  Instruments  and Hedging  Activities." At
September  30,  2003,  these  instruments  had a net fair  market  value of $1.3
million,  which was recorded on the  Consolidated  Balance  Sheet.  Based on the
non-hedge  designation  of these  instruments,  the gain was  recognized  in the
Consolidated Statement of Income.


                                       70
<PAGE>

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

The following  table sets forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at September 30, 2003.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                           Year of     Volumes        Floor          Ceiling        Fixed Price        Current Price      Fair Value
     Type of Contract      Maturity      mmcf          ($)             ($)             ($)                 ($)              ($000)
------------------------------------------------------------------------------------------------------------------------------------
<S>                         <C>        <C>        <C>             <C>             <C>                 <C>                   <C>
Options                      2003        2,650     4.00 - 5.00     5.15 - 6.00               -         4.90 - 5.13             (712)
                             2004        7,420     4.00 - 5.00     5.15 - 6.00               -         4.83 - 5.25             (411)

Swaps                        2003       10,710               -               -     5.00 - 6.23         4.90 - 5.13           (5,304)
                             2004       20,530               -               -     4.42 - 6.23         4.83 - 5.25           (6,848)
------------------------------------------------------------------------------------------------------------------------------------
                                        41,310                                                                              (13,275)
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

Physically-Settled  Commodity Derivative Instruments:  Derivative Implementation
Group ("DIG") Issue C15 and C16 of SFAS 133, as amended and interpreted,  ("SFAS
133")  establishes  criteria that must be satisfied in order for option-type and
forward  contracts in electricity to be exempted as normal  purchases and sales,
and relates to the exemption (as normal purchases and normal sales) of contracts
that combine a forward contract and a purchased  option  contract.  Based upon a
continuing  review of our  physical  gas and electric  commodity  contracts,  we
determined  that  certain  contracts  for the  physical  purchase of natural gas
associated  with our regulated gas utilities are not exempt as normal  purchases
from the  requirements  of SFAS 133. At September  30,  2003,  the fair value of
these contracts was $2.8 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: In May 2003, we entered into interest rate
swap  agreements  in which we swapped  $250 million of 7.25 % fixed rate debt to
floating rate debt. Under the terms of the agreements, we will receive the fixed
coupon  rate  associated  with  these  bonds and pay our swap  counterparties  a
variable  interest rate based on LIBOR,  that is reset on a  semi-annual  basis.


                                       71
<PAGE>

These swaps are  designated  as  fair-value  hedges and qualify for  "short-cut"
hedge accounting treatment under SFAS 133. During the period ended September 30,
2003, we paid our  counterparty an interest rate of 6.42%,  and as a result,  we
realized  interest  savings  of $0.4  million.  The  fair  market  value of this
derivative was $1.4 million at September 30, 2003.

During  2002,  we  had  interest  rate  swap  agreements  in  which  we  swapped
approximately  $1.3 billion of fixed rate debt to floating rate debt.  Under the
terms of the agreements, we received the fixed coupon rate associated with these
bonds and paid the swap  counterparties a variable  interest rate that was reset
on a quarterly  basis.  These swaps were  designated  as  fair-value  hedges and
qualified for "short-cut" hedge accounting treatment under SFAS 133. In 2002, we
terminated two of these interest rate swap agreements with an aggregate notional
amount of $1.0  billion.  The  remaining  swap,  which had a notional  amount of
$270.0  million,  was terminated on February 25, 2003. We received $18.4 million
from our swap  counterparties  as a result of the latter  termination,  of which
$8.1 million  represented  accrued swap  interest.  The  difference  between the
termination settlement amount and the amount of accrued interest, $10.3 million,
was  recorded to earnings  in the first  quarter of 2003.  This swap was used to
hedge a portion of our  outstanding  promissory  notes to LIPA.  As discussed in
Note 5 "Long-Term  Debt," we called a portion of these  promissory  notes during
the first quarter of 2003.

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

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

In October  2003,  we entered  into  heating-degree  day call and put options to
mitigate the effect of  fluctuations  from normal  weather on KEDNE's  financial
position and cash flows for the 2003/2004  winter heating season - November 2003
through March 2004. With respect to sold call options,  KeySpan will be required
to make a payment of $27,500 per heating degree day to its  counterparties  when
actual weather  experienced during this time frame is above 4,440 heating degree


                                       72
<PAGE>

days, which equates to approximately 2% colder than normal weather, based on the
most recent 20-year average for normal  weather.  The maximum amount KeySpan may
be required to pay on its sold call  options is $5.5  million.  With  respect to
purchased  put options,  KeySpan  will receive a $27,500 per heating  degree day
payment  from its  counterparties  when actual  weather is below  4,266  heating
degree days, or approximately 2% warmer than normal.  The maximum amount KeySpan
may receive on its purchased put options is $11 million.  The total premium cost
for these  options  was $0.4  million.  We will  account  for these  derivatives
pursuant to the requirements of EITF 99-2.

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


Item 4. Controls and Procedures

KeySpan maintains "disclosure controls and procedures",  as such term is defined
under Exchange Act Rule 13a-15(e),  that are designed to ensure that information
required to be disclosed by KeySpan in the reports it files or submits under the
Securities  Exchange Act of 1934, as amended (the "Exchange  Act"), is recorded,
processed,  summarized  and reported  within the time  periods  specified in the
Securities and Exchange  Commission's rules and forms, and that such information
is accumulated  and  communicated to KeySpan's  management,  including its Chief
Executive  Officer and Chief Financial  Officer,  as appropriate to allow timely
decisions regarding required disclosure.

An  evaluation  of  the  effectiveness  of  KeySpan's  disclosure  controls  and
procedures as of September 30, 2003 was conducted under the supervision and with
the  participation  of KeySpan's  Chief  Executive  Officer and Chief  Financial
Officer.  Based on that evaluation,  KeySpan's Chief Executive Officer and Chief
Financial  Officer  have  concluded  that  KeySpan's   disclosure  controls  and
procedures  were  adequate  and  designed  to ensure that  material  information
relating to KeySpan and its consolidated subsidiaries would be made known to the
Chief  Executive  Officer and Chief  Financial  Officer by others  within  those
entities,  particularly  during the  periods  when  periodic  reports  under the
Exchange  Act are  being  prepared.  Furthermore,  there  has been no  change in
KeySpan's  internal control over financial  reporting,  identified in connection
with the evaluation of such control,  that occurred during KeySpan's last fiscal
quarter that has  materially  affected,  or is  reasonably  likely to materially
affect,  KeySpan's  internal  control  over  financial  reporting.  Refer to the
Certifications  by KeySpan's Chief Executive Officer and Chief Financial Officer
filed as exhibits 31.1 and 31.2 to this report.


                                       73
<PAGE>


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

Item 1. Legal Proceedings

See Note 8 to the Consolidated  Financial Statements  "Financial  Guarantees and
Contingencies."

Item 6.  Exhibits and Reports on Form 8-K

(a)  Exhibits

31.1*Certification  of the  Chairman  and Chief  Executive  Officer  pursuant to
     Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*Certification  of the Executive Vice President and Chief Financial  Officer
     pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*Certification  of the  Chairman  and Chief  Executive  Officer  pursuant to
     Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*Certification  of the Executive Vice President and Chief Financial  Officer
     pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b)  Reports on Form 8-K

In our report on Form 8-K dated On August 6, 2003,  we reported that KeySpan had
issued a press release concerning, among other things, its financial results for
the quarter ended June 30, 2003.

In our report on Form 8-K dated September 26, 2003, we reported that KeySpan had
issued a press  release  announcing  the election of Robert J. Fani as President
and Chief Operating  Officer,  the election of Steven L. Zelkowitz as President,
Energy Assets and Supply Group and the continued  role of Wallace P. Parker Jr.,
as President, Energy Delivery and Customer Relationship Group.

In our  report  on Form  8-K  dated  October  15,  2003,  we  reported  that our
subsidiary,  KeySpan  Generation,  LLC had  agreed to pay  $400,000  to settle a
proceeding in which a jury rendered a verdict  against KeySpan  Generation,  LLC
and other  defendants  in the amount of $47 million for injuries  from  asbestos
exposure at generating  facilities  formerly  owned by the Long Island  Lighting
Company and others.
----------------------
*Filed Herewith







                                       74
<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 5, 2003                        /s/ Gerald Luterman
                                                  ------------------
                                                  Gerald Luterman
                                                  Executive Vice President and
                                                  Chief Financial Officer




























                                       75