SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   FORM 10-K/A
                                 Amendment No. 1

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

            For the period from January 1, 2002 to December 31, 2002

                         Commission File Number 1-14161

                               KEYSPAN CORPORATION
             (Exact name of registrant as specified in its charter)

             NEW YORK                                    11-3431358
(State or other jurisdiction of             (I.R.S. employer identification no.)
 incorporation or organization)
 One MetroTech Center, Brooklyn, New York                     11201
 175 East Old Country Road, Hicksville, New York              11801
 (Address of principal executive offices)                  (Zip code)

                            (718) 403-1000 (Brooklyn)
                           (516) 755-6650 (Hicksville)
              (Registrant's telephone number, including area code)

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

       Title of each class             Name of each exchange on which registered
       -------------------             -----------------------------------------
  Common Stock, $.01 par value                     New York Stock Exchange
                                                    Pacific Stock Exchange

Series AA Preferred Stock, $25 par value            New York Stock Exchange
                                                     Pacific Stock Exchange

           SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
                                      None
                                (Title of class)

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

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

     As of March 1, 2003, the aggregate market value of the common stock held by
non-affiliates  (156,910,326  shares) of the  registrant  was  $5,016,423,122.22
based on the closing price, on such date, of $31.97 per share.

     As of March 1, 2003,  there were 172,737,654  shares of common stock,  $.01
par value, outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE

Proxy  Statement  dated on or about March 31, 2003 is  incorporated by reference
into Part III hereof.

                                EXPLANATORY NOTE

KeySpan  Corporation  hereby amends its Form 10-K for the period from January 1,
2002 to  December  31,  2002 (the "Form  10-K") as set forth in this Form 10-K/A
(the "Form  10-K/A").  This Form 10-K/A is being  amended  solely to include the
Section 906  Certifications  of the Chief Executive  Officer and Chief Financial
Officer dated March 6, 2003,  inadvertently  omitted from our  previously  filed
Form 10-K as Exhibits  99.1 and 99.2,  as well as the  certifications, dated the
date hereof, required as a result of the filing of this amendment.

<PAGE>



                               KEYSPAN CORPORATION
                               INDEX TO FORM 10-K
<TABLE>
<CAPTION>
                                                                                                                         Page
                                                                                                                         ----

                                     Part I
<S>            <C>                                                                                                       <C>
Item 1.         Description of the Business.................................................................................1
Item 2.         Properties.................................................................................................26
Item 3.         Legal Proceedings..........................................................................................27
Item 4.         Submission of Matters to a Vote of Security Holders........................................................27

                                     Part II

Item 5.         Market for Registrant's Common Equity and Related Stockholder Matters......................................27
Item 6.         Selected Financial Data....................................................................................29
Item 7.         Management's Discussion and Analysis of Financial Condition and
                     Results of Operations.................................................................................30
Item 7A.        Quantitative and Qualitative Disclosures About Market Risk ................................................73
Item 8.         Financial Statements and Supplementary Data ...............................................................79
Item 9.         Changes in and Disagreements with Accountants on Accounting and
                     Financial Disclosure..................................................................................149

                                    Part III

Item 10.        Directors and Executive Officers of the Registrant.........................................................149
Item 11.        Executive Compensation.....................................................................................149
Item 12.        Security Ownership of Certain Beneficial Owners and Management.............................................149
Item 13.        Certain Relationships and Related Transactions.............................................................150
Item 14.        Controls and Procedures....................................................................................150
Item 15.        Exhibits, Financial Statement Schedules and Reports on Form 8-K............................................150
</TABLE>





<PAGE>

PART I

Item 1.         Description of the Business

                               Corporate Overview

KeySpan  Corporation  ("KeySpan"),  a New York  corporation,  is a member of the
Standard and Poor's 500 Index and a registered  holding company under the Public
Utility Holding Company Act of 1935, as amended ("PUHCA"). KeySpan was formed in
May 1998, as a result of the business combination of KeySpan Energy Corporation,
the parent of The Brooklyn Union Gas Company, and certain businesses of the Long
Island  Lighting  Company  ("LILCO").  On November 8, 2000, we acquired  Eastern
Enterprises  ("Eastern"),  now known as KeySpan  New  England,  LLC  ("KNE"),  a
Massachusetts  limited  liability  company[1],  which  primarily owns Boston Gas
Company  ("Boston  Gas"),  Colonial Gas Company  ("Colonial  Gas") and Essex Gas
Company  ("Essex Gas"),  gas utilities  operating in  Massachusetts,  as well as
EnergyNorth  Natural  Gas,  Inc.   ("EnergyNorth"),   a  gas  utility  operating
principally in central New Hampshire. As used herein,  "KeySpan," "we," "us" and
"our" refers to KeySpan,  its six principal gas distribution  subsidiaries,  and
its  other  regulated  and  unregulated  subsidiaries,  individually  and in the
aggregate.

Under our holding  company  structure,  we have no  independent  operations  and
conduct  substantially  all of our  operations  through  our  subsidiaries.  Our
subsidiaries  operate  in  the  following  four  businesses:  Gas  Distribution,
Electric Services, Energy Services and Energy Investments.

The Gas  Distribution  segment  consists of our six regulated  gas  distribution
subsidiaries,  which  operate in New York,  Massachusetts  and New Hampshire and
serve approximately 2.5 million customers.

The Electric  Services segment consists of subsidiaries that manage the electric
transmission  and  distribution  ("T&D")  system  owned by the Long Island Power
Authority  ("LIPA");  provide  energy  conversion  services  for  LIPA  from our
generating  facilities located on Long Island; and manage fuel supplies for LIPA
to fuel our approximate  4,200 megawatts of Long Island  generating  facilities.
The electric  services  segment also includes  subsidiaries  that own, lease and
operate  the  2,200  megawatt   Ravenswood  electric  generation  facility  (the
"Ravenswood facility"), located in Queens County in New York City.

The Energy  Services  segment  provides  energy-related  services  to  customers
primarily  located  within New York, New Jersey,  Massachusetts,  New Hampshire,
Rhode Island and Pennsylvania  through various  subsidiaries  that operate under
the following principal three lines of business: (i) home energy services;  (ii)
business solutions; and (iii) fiber optic services.

The Energy  Investments  segment  includes:  (i) gas  exploration and production
activities; (ii) domestic pipelines and gas storage facilities;  (iii) midstream
natural gas processing  activities in Canada;  and (iv) natural gas distribution
and pipeline activities in the United Kingdom.

KeySpan's vision is to be the premier energy company in the Northeastern  United
States.  Following the  acquisition of Eastern and EnergyNorth in November 2000,
KeySpan  became the largest gas  distribution  company in the  Northeast and the
fifth  largest  in the  United  States.  KeySpan's  increased  size and scope is
enabling us to provide enhanced  cost-effective  customer service;  to offer our
existing  customers  other  services and products by building  upon our existing
customer   relationships;   and  to  capitalize  on  the  above-average   growth
opportunities  for natural gas  expansion  in the  Northeast  by  expanding  our
infrastructure,  primarily on Long Island and in New England. The key element of
our business strategy is the continued focus and growth of our Gas Distribution,
Electric  Services and Energy Services  businesses.  We also continue to explore
the monetization of some or all of our non-core assets in the Energy Investments
segment.

--------
1 Pursuant to an  application on Form U-1 filed with the Securities and Exchange
Commission on May 28, 2002, Eastern Enterprises, a Massachusetts business trust,
was reorganized as KNE. The transaction involved the formation of KNE as well as
another new subsidiary named KSNE, LLC ("KSNE"),  a Delaware  limited  liability
company,  that is a  wholly-owned  subsidiary  of  KeySpan.  KNE is 99% owned by
KeySpan and 1% owned by KSNE.


                                       1
<PAGE>


Certain  statements  contained  in this  Annual  Report on Form 10-K  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 7.
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations" and "Item 7A. Quantitative and Qualitative  Disclosures About Market
Risk" relating to our future outlook,  anticipated capital expenditures,  future
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding,  are forward-looking  statements.  Such  forward-looking
statements  reflect  numerous  assumptions  and  involve  a number  of risks and
uncertainties  and actual results may differ  materially from those discussed in
such statements.

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

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

     -    fluctuations in weather and in gas and electric prices;

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

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

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

     -    implementation of new accounting standards;

     -    inflationary trends and interest rates;

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

     -    available sources and cost of fuel;

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

     -    retention of key personnel;

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

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

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

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

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


                                       2
<PAGE>


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

For any of these  statements,  KeySpan  claims the protection of the safe harbor
for forward-looking  information  contained in the Private Securities Litigation
Reform Act of 1995,  as  amended.  For  additional  discussion  on these  risks,
uncertainties  and assumptions,  see "Item 1. Description of Business," "Item 2.
Properties,"  "Item  7.  Management's   Discussion  and  Analysis  of  Financial
Condition and Results of Operations" and "Item 7A.  Quantitative and Qualitative
Disclosures About Market Risk" contained herein.

KeySpan's  principal  executive  offices  are located at One  MetroTech  Center,
Brooklyn,  New York 11201 and 175 East Old Country  Road,  Hicksville,  New York
11801 and its telephone numbers are (718) 403-1000 (Brooklyn) and (516) 755-6650
(Hicksville).  KeySpan makes available free of charge on or through its website,
http://www.keyspanenergy.com  (Investor Relations section), its annual report on
Form 10-K,  quarterly reports on Form 10-Q, current reports on Form 8-K, and all
amendments  to  those  reports  as soon as  reasonably  practicable  after  such
material is electronically filed with or furnished to the SEC.

                            Gas Distribution Overview

Our  gas  distribution  activities  are  conducted  by  our  six  regulated  gas
distribution  subsidiaries,  which operate in three states in the Northeast: New
York, Massachusetts and New Hampshire. We are the fifth largest gas distribution
company  in  the  United  States  and  the  largest  in  the   Northeast,   with
approximately  2.5 million  customers  served  within an aggregate  service area
covering 4,273 square miles. In New York, The Brooklyn Union Gas Company,  doing
business as KeySpan Energy Delivery New York ("KEDNY") provides gas distribution
services to  customers  in the New York City  Boroughs of  Brooklyn,  Queens and
Staten Island; and KeySpan Gas East Corporation doing business as 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. In Massachusetts,  Boston Gas provides gas distribution  services
in eastern and central  Massachusetts;  Colonial Gas  provides gas  distribution
services on Cape Cod and in eastern  Massachusetts;  and Essex Gas  provides gas
distribution services in eastern  Massachusetts.  In New Hampshire,  EnergyNorth
provides gas distribution  services to customers  principally located in central
New  Hampshire.  Our New England gas companies all do business as KeySpan Energy
Delivery New England ("KEDNE").

In New York, there are two separate,  but contiguous service  territories served
by KEDNY and  KEDLI,  comprising  approximately  1,417  square  miles,  and 1.66
million  customers.  In  Massachusetts,  Boston Gas,  Colonial Gas and Essex Gas
serve three contiguous service territories  consisting of 1,934 square miles and
approximately  768,000  customers.  In New Hampshire,  EnergyNorth has a service
territory  that is  contiguous  to Colonial Gas' and ranges from within 30 to 85
miles of the greater Boston area.  EnergyNorth provides service to approximately
75,000  customers  over a  service  area  of  approximately  922  square  miles.
Collectively,  KeySpan  owns and  operates gas  distribution,  transmission  and
storage  systems  that  consist of  approximately  21,000 miles of gas mains and
distribution pipelines and 576 miles of transmission  pipelines,  as well as six
major gas storage facilities.

Natural gas is offered for sale to residential and small commercial customers on
a "firm"  basis,  and to most large  commercial  and  industrial  customers on a
"firm" or  "interruptible"  basis.  "Firm" service is offered to customers under
tariffed  schedules or  contracts  that  anticipate  no  interruptions,  whereas
"interruptible"  service is offered to  customers  under  tariffed  schedules or
contracts that anticipate and permit interruption on short notice,  generally in
peak-load seasons or for system  reliability  reasons.  We have restructured our
gas supply and capacity contracts to reduce fixed costs and to minimize the risk
of stranded costs. We maintain  sufficient gas supply and capacity  contracts to
serve our customers,  maintain system reliability and system operations,  and to
meet our  obligation  to serve.  Over the long term,  we intend to minimize  our
fixed costs by  increasing  the amount of gas  purchased at points  within or in
close  proximity  to our  market  area,  which  allow  us to  contract  for firm
short-haul  transportation  capacity  from these  points  rather than  long-haul
transportation  capacity  from  production  areas.  We also engage in the use of
derivative  financial  instruments  from  time to time to  reduce  the cash flow
volatility  associated  with the purchase price for a portion of future natural
gas purchases.


                                       3
<PAGE>


Natural gas is available at any time of the year on an  interruptible  basis, if
supply is  sufficient  and the gas delivery  system is  operationally  adequate.
KeySpan  actively  promotes a competitive  retail gas market by making  capacity
available to retail  marketers  that are unable to obtain their own capacity and
are otherwise  not  participants  of a mandatory  capacity  assignment  program.
KeySpan also participates in interstate  markets by releasing  pipeline capacity
or by bundling  gas supply and  pipeline  capacity for  "off-system"  sales.  An
"off-system"  customer consumes gas at facilities located outside of our service
territories by connecting to our facilities or another transporter's  facilities
at a point of delivery agreed to by us and the customer.

KeySpan  purchases  natural  gas  for  sale to  customers  under  both  long-and
short-term  supply  contracts,  as well as on the spot market,  and utilizes its
firm  transportation  contracts to transport the gas. KeySpan also contracts for
firm  capacity in natural gas  underground  storage  facilities,  in addition to
winter peaking supplies.

KeySpan  sells gas to firm gas customers at its cost for such gas, plus a charge
designed  to  recover  the costs of  distribution  (including  a return of and a
return on capital  invested in our distribution  facilities).  We share with our
firm gas customers net revenues  (operating  revenues less the cost of gas) from
off-system sales and capacity release  transactions.  Further, net revenues from
tariff gas  balancing  services and certain  interruptible  on-system  sales are
refunded,  for most of our  subsidiaries,  to firm customers  subject to certain
sharing provisions.

Our gas operations can be significantly affected by seasonal weather conditions.
Annual revenues are substantially realized during the heating season as a result
of  higher  sales of gas due to cold  weather.  Accordingly,  operating  results
historically are most favorable in the first and fourth calendar quarters. KEDNY
and  KEDLI  each  operate   under   utility   tariffs  that  contain  a  weather
normalization  adjustment  that  significantly  offsets  variations  in firm net
revenues due to fluctuations in weather. However, the tariffs for our four KEDNE
gas  distribution   companies  do  not  contain  such  a  weather  normalization
adjustment and,  therefore,  fluctuations in seasonal weather conditions between
years may have a significant  effect on results of operations and cash flows for
these four subsidiaries.

Further  information and statistics  regarding our Gas Distribution  segment see
Item 7. Management's  Discussion and Analysis of Financial Condition and Results
of Operations, "Gas Distribution."

New York Gas Distribution System - KEDNY and KEDLI

Supply and Storage

KEDNY and KEDLI have firm long-term contracts for the purchase of transportation
and  underground  storage  services.  Gas supplies are purchased  under long and
short-term  firm  contracts,  as well as on the spot  market.  Gas  supplies are
transported by interstate  pipelines  from domestic and Canadian  supply basins.
Peaking  supplies are available to meet system  requirements on the coldest days
of the winter season.

Peak-Day Capability.  The design criteria for the New York gas system assumes an
average  temperature  of 0(0)F for  peak-day  demand.  Under such  criteria,  we
estimate that the  requirements to supply our firm gas customers would amount to
approximately  2,025 MDTH of gas for a peak-day during the 2002/03 winter season
and that the gas  available  to us on such a peak-day  amounts to  approximately
2,026 MDTH. For the 2003/04 winter season, we estimate the peak-day requirements
will amount to 2,088 MDTH and that the gas  supplies  available  to us on such a
peak-day will amount to  approximately  2,001 MDTH; we have plans for additional
purchases to offset the peak-day  supply  deficit.  The 2002/03 winter  peak-day
throughput to our New York  customers was 1,754 MDTH,  which occurred on January
23, 2003 at an average temperature of 14 degrees F, representing 87% of our peak
day capability.  Our New York firm gas peak-day  capability is summarized in the
following table:



                                       4
<PAGE>


<TABLE>
<CAPTION>
Source                                                                 MDTH per day            % of Total
---------------------------------------------------------------  --------------------- ---------------------
<S>                                                                       <C>                      <C>
Pipeline                                                                    744                     37%
Underground Storage                                                         778                     38%
Peaking Supplies                                                            504                     25%
                                                                            ---                     ---
Total                                                                      2,026                    100%
                                                                 =====================  =====================
</TABLE>

Pipelines.  Our New York based gas distribution  utilities  purchase natural gas
for sale under contracts with suppliers with natural gas located in domestic and
Canadian  supply  basins and arrange for its  transportation  to our  facilities
under firm  long-term  contracts with  interstate  pipeline  companies.  For the
2002/03  winter,  approximately  75% of our New  York  natural  gas  supply  was
available from domestic sources and 25% from Canadian sources. We have available
under  firm  contract  744  MDTH per day of  year-round  and  seasonal  pipeline
transportation  capacity.  Major providers of interstate  pipeline  capacity and
related  services  to us  include:  Transcontinental  Gas Pipe Line  Corporation
("Transco"),  Texas Eastern  Transmission  Corporation  ("Tetco"),  Iroquois Gas
Transmission System ("Iroquois"),  Tennessee Gas Pipeline Company ("Tennessee"),
Dominion  Transmission  Incorporated  ("Dominion"),  and Texas Gas  Transmission
Company.

Underground  Storage.  In order to meet  winter  demand in our New York  service
territories,  we also have long-term contracts with Transco,  Tetco,  Tennessee,
Dominion,  Equitrans,  Inc., and Honeoye Storage  Corporation  ("Honeoye"),  for
underground  storage  capacity  of 59,058  MDTH and 778 MDTH per day of  maximum
deliverability.

Peaking Supplies. In addition to the pipeline and underground storage supply, we
supplement our winter supply  portfolio with peaking supplies that are available
on the coldest days of the year to economically meet the increased  requirements
of our  heating  customers.  Our peaking  supplies  include:  (i) two  liquefied
natural gas ("LNG")  plants;  and (ii) peaking  supply  contracts with five dual
fuel power  producers  located in our franchise  areas.  For the 2002/03  winter
season,  we had the capability to provide a maximum  peak-day supply of 504 MDTH
on  excessively   cold  days.  The  LNG  plants  have  a  storage   capacity  of
approximately  2,053 MDTH and peak-day throughput capacity of 394.5 MDTH, or 19%
of  peak-day  supply.   We  also  have  contract  rights  with  Trigen  Services
Corporation,   Brooklyn  Navy  Cogeneration   Partners,  LP,  Nissequogue  Cogen
Partners,  TBG Cogen  Partners,  and NYPA to purchase  peaking  supplies  with a
maximum daily capacity of 110 MDTH and total available  peaking  supplies during
the winter season of 3,349 MDTH.

Gas Supply Management.

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.  The agreement with Coral expires on March 31, 2003. In  anticipation  of
the  expiration  of the existing  agreement,  a request for proposal was sent to
various portfolio managers.  Upon evaluation of the bids, KeySpan will negotiate
an agreement for its gas distribution subsidiaries.  It is anticipated that such
agreement will become effective April 1, 2003.

Gas Costs.  Fluctuations in gas costs have little direct impact on the financial
results of KEDNY and KEDLI,  since the  current  gas rate  structure  of each of
these companies  includes a gas adjustment  clause pursuant to which  variations
between  actual  gas  costs  incurred  and gas costs  billed  are  deferred  and
subsequently refunded to or collected from customers.



                                       5
<PAGE>

Deregulation.  Regulatory actions, economic factors and changes in customers and
their preferences continue to reshape our gas operations.  A number of customers
currently  purchase  their gas  supplies  from  natural gas  marketers  and then
contract  with  us for  local  transportation,  balancing  and  other  unbundled
services.  In addition,  our New York gas  distribution  companies  release firm
capacity on our  interstate  pipeline  transportation  contracts  to natural gas
marketers to ensure the  marketers'  gas supply is delivered on a firm basis and
in a  reliable  manner.  As of  February  1,  2003,  approximately  119,776  gas
customers have opted to purchase their gas from marketers.

New England Gas Distribution Systems

Supply and Storage

KEDNE has firm  long-term  contracts  for the  purchase  of  transportation  and
underground  storage  services.  Gas  supplies  are  purchased  under  long  and
short-term  firm  contracts,  as well as on the spot  market.  Gas  supplies are
transported by interstate pipelines from domestic and Canadian supply basins. In
addition,  peaking  supplies,  principally  liquefied  natural gas ("LNG"),  are
available to meet system requirements during the winter season.

Peak-Day Capability. The design criteria for our New England gas systems assumes
an average temperature of -6(0)F for peak-day demand. Under such criteria, KEDNE
estimates that the  requirements to supply their firm gas customers would amount
to  approximately  1,231 MDTH of gas for a peak-day during the 2002/2003  winter
season  and  that the gas  available  to KEDNE  on such a  peak-day  amounts  to
approximately 1,347 MDTH. For the 2003/2004 winter season,  KEDNE estimates that
the  peak-day  requirements  will amount to 1,266 MDTH and that the gas supplies
available on such a peak-day will amount to approximately 1,412 MDTH.

As of March 1, 2003, the highest daily  throughput to our New England  customers
was 1,203 MDTH, which occurred on January 22, 2003 at an average  temperature of
9'F.  KEDNE has  sufficient gas available to meet the  requirements  of their
firm gas customers for the  2002/2003  winter gas season.  The firm gas peak day
capability of KEDNE is summarized in the following table:

<TABLE>
<CAPTION>
Source                                                                        MDTH per day               % of Total
---------------------------------------------------------------------    ---------------------  ----------------------
<S>                                                                             <C>                        <C>
Pipeline                                                                           412                        31
Underground Storage                                                                270                        20
Peaking Supplies                                                                   665                        49
Total                                                                             1347                       100
                                                                          =====================  ======================
</TABLE>

Pipelines. Our New England based gas distribution utilities purchase natural gas
for sale under contracts with suppliers with natural gas located in domestic and
Canadian supply basins and arrange for  transportation to their facilities under
firm long-term contracts with interstate pipeline companies.  Major providers of
interstate  pipeline  capacity  and  related  services  to the  KEDNE  companies
include:  Tetco,  Iroquois,   Maritimes  and  Northeast  Pipelines,   Tennessee,
Algonquin Gas Transmission Company and Portland Natural Gas Transmission System.

Underground Storage. KEDNE has available under firm contract 682 MDTH per day of
year-round and seasonal transportation and underground storage capacity to their
facilities in New England. KEDNE has long-term contracts with Tetco,  Tennessee,
Dominion,  National  Fuel Gas Supply  Corporation  and Honeoye  for  underground
storage capacity of 23,279 MDTH and 270 MDTH per day of maximum deliverability.



                                       6
<PAGE>

Peaking  Supplies.  The KEDNE gas supply portfolio is supplemented  with peaking
supplies that are available on the coldest days  throughout the winter season in
order to economically meet the increased  requirements of our heating customers.
Peaking supplies include gas provided by both LNG and propane air plants located
within the  distribution  system,  as well as two leased  facilities  located in
Providence,  Rhode Island and Everett, MA. For the 2002/2003 winter season, on a
peak-day,  KEDNE has access to 665 MDTH of  peaking  supplies,  49% of  peak-day
supply.


Gas Supply  Management.  From November 1, 1999 through October 31, 2002, the New
England  based  gas  distribution   subsidiaries   operated  under  a  portfolio
management  contract with El Paso Merchant Energy ("El Paso").  El Paso provided
the  majority of the city gate supply  requirements  to the four New England gas
distribution  companies (Boston Gas, Colonial Gas, Essex Gas and EnergyNorth) at
market prices and managed upstream capacity, underground storage and term supply
contracts.  We negotiated a new agreement  with  Entergy-Koch  that replaced the
expired El Paso  agreement.  The new agreement  with  Entergy-Koch  commenced on
November 1, 2002 and extends  through  March 31, 2003.  In  anticipation  of the
expiration of the existing agreement, a request for proposal was sent to various
portfolio  managers.  Upon  evaluation  of the bids,  KeySpan will  negotiate an
agreement for its gas  distribution  subsidiaries.  It is anticipated  that such
agreement will become effective April 1, 2003.

Gas Costs. Fluctuations in gas costs have little impact on the operating results
of the KEDNE  companies  since the  current gas rate  structure  for each of the
companies  include gas adjustment  clauses pursuant to which variations  between
actual gas costs  incurred and gas costs  billed are  deferred and  subsequently
refunded to or  collected  from  customers.  The KEDNE  companies  do not have a
weather  normalization  adjustment  clause  and as a result,  fluctuations  from
normal  weather  may have a positive  or negative  impact on their  results.  To
lessen to some extent the effect of flucuations  in normal  weather  patterns on
KEDNE's results of operations and cash flows,  weather  derivatives are in place
for the 2002/2003 winter heating season.

For additional  information  concerning the gas  distribution  segment,  see the
discussion  in  "Item 7.  Management's  Discussion  and  Analysis  of  Financial
Condition and Results of Operations - Gas Distribution" contained herein.

                           Electric Services Overview

We are the largest  investor  owned  electric  generator in New York State.  Our
subsidiaries own and operate 5 large generating plants and 8 smaller  facilities
which are  comprised of 57  generating  units in Nassau and Suffolk  Counties on
Long Island and the Rockaway Peninsula in Queens. In addition, we own, lease and
operate a major  generating  facility  in Queens  County in New York  City,  the
Ravenswood facility, which is comprised of 3 large steam-generating units and 17
gas turbine generators.

As  more  fully  described  below,  we:  (i)  provide  to  LIPA  all  operation,
maintenance and construction  services and significant  administrative  services
relating to the Long  Island  electric  transmission  and  distribution  ("T&D")
system through a management  services  agreement  (the "MSA");  (ii) supply LIPA
with generating  capacity,  energy  conversion and ancillary  services through a
power supply  agreement (the "PSA") to allow LIPA to provide  electricity to its
customers  on Long  Island;  and (iii) manage all aspects of the fuel supply for
our Long Island  generating  facilities,  as well as all aspects of the capacity
and energy  owned by or under  contract  to LIPA  through  an energy  management
agreement (the "EMA").  Each of the MSA, PSA and EMA became effective on May 28,
1998 and are collectively referred to herein as the "LIPA Agreements."



                                       7
<PAGE>

Generating Facility Operations

In June 1999, we acquired the 2,200 megawatt  Ravenswood facility located in New
York City from  Consolidated  Edison  Company of New York,  Inc.  ("Consolidated
Edison") for  approximately  $597  million.  In order to reduce our initial cash
requirements to finance this acquisition, we entered into an arrangement with an
unaffiliated  variable  interest  entity  through which we lease the  Ravenswood
facility. Under the arrangement, the variable interest entity acquired a portion
of the facility  directly from  Consolidated  Edison and leased it to our wholly
owned subsidiary.  We have guaranteed all payment and performance obligations of
our subsidiary under the lease. The lease relates to approximately  $425 million
of the acquisition cost of the facility,  which is the amount of debt that would
have been recorded on our Consolidated  Balance Sheet had the variable  interest
entity not been utilized and conventional debt financing been employed. Further,
we would have recorded an asset in the same amount.  Monthly lease  payments are
for interest  only.  The lease  qualifies as an  operating  lease for  financial
reporting  purposes  while  preserving our ownership of the facility for federal
and state  income tax  purposes.  We believe  that the fair market  value of the
Ravenswood  facility,  including  the  leased  facilities,  is in  excess of its
acquisition cost (see discussion  concerning the Financial  Accounting Standards
Board  issued  Interpretation  No. 46 in "Item 7.  Management's  Discussion  and
Analysis of Financial Condition and Results of Operations").

The Ravenswood  facility sells capacity,  energy and ancillary services into the
New York  Independent  System Operator  ("NYISO")  energy market at market-based
rates, subject to mitigation. The plant has the ability to provide approximately
25% of New York City's  capacity  requirements  and is a strategic asset that is
available  to serve  residents  and  businesses  in New York  City.  Reliability
improvement  investments  at our Ravenswood  facility  reduced the forced outage
rate for that  facility  from  35% in 1999 to under 6% in 2000,  2001 and  2002.
Decreasing the amount of time our generating units are offline for repair allows
us to increase  sales.  We are also in the process of expanding  our  Ravenswood
facility  by adding a  250-megawatt  state-of-the-art  gas-fired  combined-cycle
unit. On September 5, 2001, we received approval for the expansion from New York
State's Siting Board on Electric Generation and the Environment ("Siting Board")
and  construction  is  underway.  We  anticipate  that  the  new  unit  will  be
operational  in late 2003.  Further,  two 79.9  megawatt  generating  facilities
located on Long  Island  were  placed  into  service in June and July 2002.  The
capacity of and energy from these facilities are dedicated to LIPA under 25 year
contracts.

The competitive  wholesale  market for capacity,  energy and ancillary  services
administered  by the NYISO is still evolving and the Federal  Energy  Regulatory
Commission  ("FERC") has adopted  several price  mitigation  measures  which are
subject to rehearing and possible  judicial  review.  See "Item 7.  Management's
Discussion    and   Analysis   of   Financial    Condition    and   Results   of
Operation-Regulatory   Issues  and  Competitive   Environment"  for  a  further
discussion of these matters.

Natural gas or oil can be used to power 45 of our 77 generating units. In recent
years,  we have  reconfigured  several of our  facilities to enable them to burn
either natural gas or oil, thus enabling us to switch periodically  between fuel
alternatives based upon cost and seasonal  environmental  requirements.  Through
other innovative  technological  approaches,  we increased installed capacity in
our generating facilities by 80 megawatts, and we instituted a program to reduce
nitrogen oxides for improved environmental performance.


                                       8
<PAGE>
<TABLE>
<CAPTION>
The following table indicates the 2003 summer capacity of all of our steam
generation facilities and gas turbine ("GT") units as reported to the NYISO:

----------------------------------------------------------------------------------------------------------------------------
Location of Units                         Description                    Fuel                 Units               MW
----------------------------------------------------------------------------------------------------------------------------
<S>                                      <C>                           <C>                   <C>                 <C>
Long Island City                          Steam Turbine                 Dual*                  3                  1,755
Northport, L.I.                           Steam Turbine                 Dual*                  4                  1,520
Port Jefferson, L.I.                      Steam Turbine                 Dual*                  2                    385
Glenwood, L.I.                            Steam Turbine                 Gas                    2                    229
Island Park, L.I.                         Steam Turbine                 Dual*                  2                    389
Far Rockaway, L.I.                        Steam Turbine                 Dual*                  1                    110
Long Island City                          GT Units                      Dual*                 17                    455
Throughout L.I.                           GT Units                      Dual*                 16                    471
Throughout L.I.                           GT Units                      Oil                   30                  1,093

TOTAL                                                                                         77                  6,407
============================================================================================================================
</TABLE>

*Dual - Oil (#2 oil, #6 residual oil) or kerosene, and natural gas

In addition  to the 250 MW  expansion  of the  Ravenswood  facility,  we plan to
construct  another 250 MW combined  cycle plant in  Melville,  Long  Island.  In
January  2002,  we filed an  application  for approval with the Siting Board for
this project, and in February 2003, the Presiding Examiners issued a Recommended
Decision recommending that the Siting Board issue a Certificate of Environmental
Capability  and  Public  Need for the  project.  Action by the  Siting  Board is
expected  in  March  2003.  In  addition,  as part of our  growth  strategy,  we
continually   evaluate  the  possible   acquisition  of  additional   generating
facilities in the Northeast.  However,  we are unable to predict when or if such
facilities  will be acquired and the effect any such  acquired  facilities  will
have on our financial condition, results of operations or cash flows.

LIPA Agreements

LIPA is a corporate municipal instrumentality and a political subdivision of the
State of New York.  On May 28,  1998,  certain  of LILCO's  business  units were
merged with KeySpan and LILCO's common stock and remaining  assets were acquired
by  LIPA.  At the  time of  this  transaction,  three  major  long-term  service
agreements were also executed  between KeySpan and LIPA that provide for KeySpan
to provide 4,037 MW of power generation capacity and energy conversion services;
operation,  maintenance and capital improvement services for LIPA's transmission
and distribution system; and the performance of energy management services.

Power Supply Agreement.  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.  Under the terms
of the PSA, rates will be reestablished for the contract year commencing January
1, 2004 by  recalculating  the revenue  requirement  underlying  those rates. We
anticipate  submitting  to the FERC a rate filing  reflecting  the  recalculated
revenue requirement in the Fall of 2003. We are unable to predict the outcome of
that proceeding at this time. Rates charged to LIPA include a fixed and variable
component.  The variable  component is billed to LIPA on a monthly  basis and is
dependent on the number of megawatt hours dispatched.  LIPA has no obligation to
purchase  energy  conversion  services from us and is able to purchase energy or
energy  conversion  services on a least-cost  basis from all  available  sources
consistent with existing interconnection  limitations of the T&D system. The PSA
provides  incentives  and penalties  that can total $4 million  annually for the
maintenance  of the  output  capability  and the  efficiency  of the  generating
facilities. In 2002, we earned $4 million in incentives under the PSA.


                                       9
<PAGE>


The PSA runs for a term of fifteen years. The PSA is renewable for an additional
15 years on similar terms at LIPA's option.  However,  the PSA provides LIPA the
option of electing to reduce or "ramp-down" the capacity it purchases from us in
accordance with agreed-upon schedules. In years seven through ten of the PSA, if
LIPA elects to  ramp-down,  we are  entitled to receive  payment for 100% of the
present value of the capacity charges  otherwise payable over the remaining term
of the PSA. If LIPA ramps-down the generation capacity in years 11 through 15 of
the PSA,  the  capacity  charges  otherwise  payable  by LIPA will be reduced in
accordance  with a  formula  established  in the  PSA.  If  LIPA  exercises  its
ramp-down  option,  KeySpan may use any capacity  released by LIPA to bid on new
LIPA capacity  requirements  or to replace  other  ramped-down  capacity.  If we
continue  to  operate  the  ramped-down  capacity,  the PSA  requires  us to use
reasonable  efforts  to market the  capacity  and  energy  from the  ramped-down
capacity and to share any profits with LIPA.  The PSA will be  terminated in the
event that LIPA  exercises its right to purchase,  at fair market value,  all of
the Long Island generating facilities pursuant to the Generation Purchase Rights
Agreement discussed in greater detail below.

We also have an inventory of sulfur  dioxide  ("SO2") and nitrogen oxide ("NOx")
emission  allowances that may be sold to third party  purchasers.  The amount of
allowances  varies from year to year relative to the level of emissions from the
Long Island  generating  facilities,  which is greatly  dependent  on the mix of
natural gas and fuel oil used for generation  and the amount of purchased  power
that is imported onto Long Island.  In accordance  with the PSA, 33% of emission
allowance sales revenues  attributable to the Long Island generating  facilities
is retained  by KeySpan  and the other 67% is credited to LIPA.  LIPA also has a
right of first refusal on any  potential  emission  allowance  sales of the Long
Island generating facilities.  Additionally,  KeySpan voluntarily entered into a
memorandum of understanding  with the New York State Department of Environmental
Conservation ("DEC"), which memorandum prohibits the sale of SO2 allowances into
certain  states and requires the purchaser to be bound by the same  restriction,
which may marginally affect the market value of the allowances.

Management  Services Agreement.  Under the MSA, we perform day-to-day  operation
and maintenance  services and capital  improvements for LIPA's  transmission and
distribution  system,  including,   among  other  functions,   transmission  and
distribution  facility  operations,  customer  service,  billing and collection,
meter reading, planning,  engineering, and construction,  all in accordance with
policies and procedures  adopted by LIPA.  KeySpan furnishes such services as an
independent  contractor and does not have any ownership or leasehold interest in
the transmission and distribution system.

In exchange for providing  these  services,  we are  reimbursed for our budgeted
costs and entitled to earn an annual  management fee of $10 million and may also
earn certain  cost-based  incentives,  or be responsible for certain  cost-based
penalties.  The incentives provide for us to retain 100% of the first $5 million
of budget underruns and 50% of any additional  budget underruns up to 15% of the
total cost budget. Thereafter, all savings accrue to LIPA. The penalties require
us to absorb any total cost  budget  overruns  up to a maximum of $15 million in
any contract year.

In  addition  to the  foregoing  cost-based  incentives  and  penalties,  we are
eligible  for   performance-based   incentives  for  performance  above  certain
threshold  target  levels and subject to  disincentives  for  performance  below
certain other  threshold  levels,  with an  intermediate  band of performance in
which neither incentives nor disincentives  will apply, for system  reliability,
worker  safety,  and  customer  satisfaction.  In 2002,  we earned $7 million in
non-cost performance incentives.

The MSA was originally  set to expire on May 28, 2006, but was extended  through
December  31,  2008.  The MSA was  extended in exchange  for an extension of the
option  period  under the  Generation  Purchase  Rights  Agreement as more fully
described in the discussion on "Generation Purchase Rights Agreement" below.

Energy  Management  Agreement.  Pursuant to the EMA,  KeySpan (i)  procures  and
manages  fuel  supplies for LIPA to fuel our Long Island  generating  facilities
acquired  from  LILCO in 1998,  (ii)  performs  off-system  capacity  and energy
purchases on a least-cost basis to meet LIPA's needs, and (iii) makes off-system
sales of output  from the Long  Island  generating  facilities  and other  power
supplies  either owned or under contract to LIPA. LIPA is entitled to two-thirds
of the profit from any off-system electricity sales arranged by us. The term for
the fuel supply service provided in (i) above is fifteen years, expiring May 28,
2013, and the term for the off-system  purchases and sales services  provided in
(ii) and (iii) above is eight years, expiring May 28, 2006.



                                       10
<PAGE>

In exchange for these services,  we earn an annual fee of $1.5 million,  plus an
allowance for certain costs  incurred in performing  services under the EMA. The
EMA further provides  incentives and disincentives up to $5 million annually for
control  of the cost of fuel and  electricity  purchased  on behalf of LIPA.  In
2002, we earned EMA incentives in an aggregate of $5 million.

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

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

Other Rights.  Pursuant to other agreements  between LIPA and us, certain future
rights have been granted to LIPA.  Subject to certain  conditions,  these rights
include  the  right for 99 years to lease or  purchase,  at fair  market  value,
parcels  of land and to  acquire  unlimited  access  to, as well as  appropriate
easements  at,  the  Long  Island  generating  facilities  for  the  purpose  of
constructing  new  electric  generating  facilities  to be  owned by LIPA or its
designee.  Subject to this right granted to LIPA,  KeySpan has the right to sell
or lease property on or adjoining the Long Island generating facilities to third
parties.  In  addition,  LIPA has  acquired  a parcel of land at the site of the
former  Shoreham  Nuclear  Power  Station  site  suitable as the  terminus for a
potential  transmission cable under Long Island Sound or the potential site of a
new gas-fired combined cycle generating facility.

We own the common plant (such as  administrative  office  buildings and computer
systems)  formerly owned by LILCO and recover an allocable share of the carrying
costs of such plant through the MSA.  KeySpan has agreed to provide LIPA,  for a
period of 99 years,  the right to enter  into  leases at fair  market  value for
common  plant or  sub-contract  for  common  services  which it may  assign to a
subsequent  manager of the transmission and  distribution  system.  We have also
agreed:  (i) for a period of 99 years not to compete  with LIPA as a provider of
transmission or distribution  service on Long Island;  (ii) that LIPA will share
in synergy (i.e.,  efficiency)  savings over a 10-year period  attributed to the
May 28, 1998 transaction  which resulted in the formation of KeySpan  (estimated
to be  approximately $1 billion),  which savings are incorporated  into the cost
structure under the LIPA Agreements; and (iii) generally not to commence any tax
certiorari case (until termination of the PSA) challenging  certain property tax
assessments relating to the former LILCO Long Island generating facilities.

Guarantees and Indemnities. We have entered into agreements with LIPA to provide
for the  guarantee  of  certain  obligations,  indemnification  against  certain
liabilities  and  allocation  of   responsibility   and  liability  for  certain
pre-existing  obligations and liabilities.  In general,  liabilities  associated
with the LILCO assets transferred to KeySpan,  have been assumed by KeySpan; and
liabilities  associated  with the assets  acquired  by LIPA,  are borne by LIPA,
subject to certain specified exceptions. We have assumed all liabilities arising
from  all   manufactured   gas  plant  ("MGP")   operations  of  LILCO  and  its
predecessors,  and LIPA has assumed certain  liabilities  relating to the former
LILCO Long Island  generating  facilities and all  liabilities  traceable to the
business  and  operations  conducted  by  LIPA  after  completion  of  the  1998
KeySpan/LILCO  transaction.  An agreement  also  provides for an  allocation  of
liabilities  which  relate to the assets that were common to the  operations  of
LILCO  and/or  shared  services  and are not  traceable  directly  to either the
business or operations conducted by LIPA or KeySpan.

Other. In late 2002, LIPA announced,  and we acknowledged,  that during 2001 and
2002 we had made an error in  reporting  LIPA's  electric  system  requirements,
resulting in an overestimation of LIPA's unbilled revenue. LIPA and KeySpan have
continued to review and audit the reporting  electric  system  requirements  for
2002 and earlier periods,  and have determined that, in addition to the 2001 and
2002  overestimation,  unbilled revenues for prior periods back to May 1998 were
slightly  underestimated.  Based on the  review,  the  total  overestimation  in
unbilled  revenue was  approximately  $65 million.  The LIPA revenue  estimation
error did not have an impact on LIPA's  electric  rates charged to its customers
or to its cash  balances.  We do not believe  that the LIPA  revenue  estimation
error will have any material adverse impact on the various  agreements with LIPA
or on our financial or operating performance.


                                       11
<PAGE>

For additional  information  concerning the Electric services  segment,  see the
discussion  in  "Item 7.  Management's  Discussion  and  Analysis  of  Financial
Condition and Results of Operations - Electric Services" contained herein.

                            Energy Services Overview

Our Energy Services segment  provides  services to customers  located  primarily
within New York,  New Jersey,  Massachusetts,  New  Hampshire,  Rhode Island and
Pennsylvania  through  various  subsidiaries  which  operate under the following
three  principal  lines of business:  (i) home energy  services,  which provides
residential  and small  commercial  customers  with service and  maintenance  of
energy  systems and  appliances,  as well as the  competitive  retail  supply of
natural  gas  and   electricity;   (ii)  business   solutions,   which  provides
engineering,  consulting  and  construction  services,  related  to the  design,
construction,  installation,  operation,  maintenance and management of heating,
cooling and power production equipment and systems for commercial and industrial
customers,  as  well  as the  competitive  retail  supply  of  natural  gas  and
electricity to large commercial, institutional and industrial customers (certain
subsidiaries  within  this line of  business  also  engage or may  engage in the
financing and ownership of cogeneration, small power production, thermal energy,
chilled  water and  related  equipment  and  facilities);  and (iii) fiber optic
services in which we construct  fiber optic systems and  facilities  and own and
lease fiber optic cable to local, long distance, and trans-Atlantic carriers, as
well as internet service providers.

The Energy  Services  segment has more than 3,000  employees and 200,000 service
contracts,  and is the number one oil to gas  conversion  contractor in New York
and New England.

KeySpan's Energy Services subsidiaries compete with local, regional and national
mechanical  contracting,  HVAC,  plumbing,  engineering,  wholesale fiber optics
carriers,  and independent energy companies,  in addition to electric utilities,
independent power producers and local distribution  companies.

Competition  is based  largely upon pricing,  availability  and  reliability  of
supply, technical and financial capabilities,  regional presence, experience and
customer service.  With our strong market presence in the Northeast  centered on
our Gas  Distribution and Electric  Services  operations and the long-term trend
towards further deregulation,  we believe that we are well positioned to provide
our customers with an expanded array of energy products and services through our
unregulated energy service companies.

In 2001,  we  discontinued  the general  contracting  activities  related to the
former Roy Kay companies  with the exception of work to be completed on existing
contracts,  based upon our view that the general contracting  business was not a
core competency of these companies.  As a result of our evaluation of the Energy
Services business  undertaken during 2001, we decided to set certain limitations
on the types of new  general  contracting  activities  in which our  contracting
subsidiaries  may engage.  We also installed senior  management  personnel whom,
among  other  things,  have  reviewed  and  continue  to review and focus on our
overall  strategy of these  businesses.  We are currently  engaged in litigation
concerning the Roy Kay companies.  For further  information,  See Note 10 to the
Consolidated Financial Statements,  "Roy Kay Operations" and Note 7 "Contractual
Obligations and Contingencies - Legal Matters for a further discussion.

Although  the Roy Kay  companies  are exiting  the  non-energy  related  general
contracting business,  KeySpan Services, Inc. ("KSI"), through its subsidiaries,
may engage in general  contracting  where such activities  involve contracts for
construction activities that management is satisfied such subsidiary,  either by
itself or through one or more contracts with other KSI subsidiaries and/or third
parties,  has the necessary  resources to perform and which are primarily energy
related as  determined  by SEC rule or precedent  under PUHCA  (e.g.,  involving
projects such as the construction of HVAC, thermal, chilled water and other HVAC


                                       12
<PAGE>

facilities,  renewable energy,  cogeneration and other types of power production
facilities and waste water treatment facilities).  KSI and its subsidiaries will
not, however,  enter into new contracts to provide general contracting  services
involving  the  construction  of primarily  non-energy  related  facilities,  as
determined by SEC rule or precedent under PUHCA.

In its order approving the  acquisition by KeySpan of Eastern,  the SEC reserved
jurisdiction on its determination of whether the Energy Services  companies were
retainable and required KeySpan to file a post-effective amendment regarding the
retention of these Energy Services companies.  On June 27, 2001, we filed such a
post-effective  amendment. The SEC has not made a determination,  but we believe
that the SEC may find ample bases to approve of KeySpan's  continued  operations
in the  Energy  Services  business,  especially  in light of the fact that other
registered holding companies have been permitted to retain their  energy-service
operations.

For additional  information  concerning  the Energy  Services  segment,  see the
discussion  in  "Item 7.  Management's  Discussion  and  Analysis  of  Financial
Condition and Results of Operations - Energy Services" contained herein.

                           Energy Investments Overview

We are also engaged in Energy Investments which include: (i) gas exploration and
production activities; (ii) domestic pipelines and gas storage facilities; (iii)
midstream  natural  gas  processing  activities  in  Canada;  (iv)  natural  gas
distribution  and pipeline  activities  in the United  Kingdom;  and (v) certain
other  domestic  energy-related  investments,  such as providing  meter  reading
equipment and services to municipal  utilities,  the  transportation by truck of
liquid  natural gas, new fuel cell  technologies  and certain  internet  related
activities.

Gas Exploration and Production

KeySpan is engaged in the exploration and production of domestic natural gas and
oil through our equity  interest in The Houston  Exploration  Company  ("Houston
Exploration") and through our wholly owned subsidiary,  KeySpan  Exploration and
Production,  LLC ("KeySpan  Exploration").  Houston Exploration was organized by
KEDNY  in 1985  to  conduct  natural  gas and  oil  exploration  and  production
activities.  It completed an initial public  offering in 1996 and its shares are
currently  traded on the New York  Stock  Exchange  under the  symbol  "THX." On
February 26, 2003,  Houston  Exploration  issued 3 million  shares of its common
stock,  the net proceeds of which were used to  repurchase  3 million  shares of
common stock owned by us. As a result of the repurchase,  our ownership interest
in Houston  Exploration was reduced from approximately 66% to approximately 56%.
Additionally,  there is an  over-allotment  option for 300,000 shares,  which if
exercised  would further reduce our ownership in Houston  Exploration to 55%. At
March  1,  2003,  Houston  Exploration's  aggregate  market  capitalization  was
approximately $842.2 million (based upon the closing price on the New York Stock
Exchange on February 28, 2003 of $27.20).  At March 1, 2003, Houston Exploration
had   approximately   30,961,618   shares  of  common  stock,  $.01  par  value,
outstanding.

KeySpan  Exploration  is engaged in a joint venture with Houston  Exploration to
explore for  natural gas and oil.  Houston  Exploration  contributed  all of its
undeveloped  offshore leases to the joint venture for a 55% working interest and
KeySpan  Exploration,  acquired a 45% working  interest in all  prospects  to be
drilled by the joint venture.  Effective 2001, the joint venture was modified to
reflect that KeySpan  Exploration  would only  participate in the development of
wells that had previously been drilled and not participate in future exploration
prospects.

In line with our stated strategy of exploring the monetization or divestiture of
certain non-core assets, in October 2002, we sold a portion of our assets in the
joint venture drilling program to Houston Exploration. We received $26.5 million
in cash for our working interests in producing properties with an estimated 18.6
Bcfe of proved and provable reserves.

Our gas exploration and production  subsidiaries focus their operations offshore
in the Gulf of Mexico and onshore in South Texas,  South  Louisiana,  the Arkoma
Basin,  East Texas and West Virginia.  The geographic  focus of these operations
enables  our  subsidiaries  to  manage a  comparatively  large  asset  base with
relatively  few  employees and to add and operate  production at relatively  low
incremental  costs.  Our gas  exploration  and production  subsidiaries  seek to
balance  their  offshore and onshore  activities so that the lower risk and more
stable production  typically  associated with onshore properties  complement the
high potential  exploratory projects in the Gulf of Mexico by balancing risk and


                                       13
<PAGE>

reducing  volatility.  Houston  Exploration's  business  strategy  is to seek to
continue to increase reserves,  production and cash flow by pursuing  internally
generated prospects,  primarily in the Gulf of Mexico, by conducting development
and  exploratory  drilling on our offshore and onshore  properties and by making
selective opportune acquisitions.

Offshore  Properties.  Our interests in offshore  properties  are located in the
shallow  waters  of the  Outer  Continental  Shelf  of the Gulf of  Mexico.  Our
interests  in key  producing  properties  are located in the western and central
Gulf of Mexico and  include the  Mustang  Island,  High  Island,  East  Cameron,
Vermilion and South  Timbalier  areas. We hold interests in 86 blocks in federal
and state  waters,  of which 42 are  developed.  Through  our  subsidiaries,  we
operate 29 of our developed blocks, which accounted for approximately 75% of our
interests in offshore  production  during 2002.  We have a total of 37 platforms
and production cassions of which we operate 27. Since its inception in 1999, the
joint  venture  participated  in 28  wells,  23 of which  were  successful--  17
exploratory  and six  development.  During 2002, we drilled ten offshore  wells,
nine of which  were  successful,  representing  a  success  rate of 90%.  Of the
successful wells drilled,  six were exploratory and three were development.  The
joint venture  participated  in four of the 2002 wells,  two exploratory and two
development, all of which were successful.

Onshore Properties.  Our interests in South Texas properties are concentrated in
the Charco,  Haynes and South Trevino  Fields of Zapata  County;  the Alexander,
Hubbard and South Laredo Fields of Webb County; and the North East Thompsonville
Field in Jim Hogg County.  We own interests in 562 producing wells, 450 of which
are operated by our  subsidiaries.  Our interests in Arkoma Basin properties are
located in two primary areas: the Chismville/Massard  Field located in Logan and
Sebastian  Counties of Arkansas and the Wilburton  and Panola Fields  located in
Latimer County,  Oklahoma. We own working interests in 252 producing natural gas
wells,  of which we operate 131. Other Onshore  properties are  concentrated  in
three areas: South Louisiana, West Virginia and East Texas. On a combined basis,
we own working interests in 708 producing wells, 653 of which we operate. During
2002, we drilled 87 onshore wells, 75 of which were  successful,  representing a
success rate of 86%. Of the successful  wells drilled,  54 were drilled in South
Texas and 21 were  drilled  in the  Arkoma  Basin.  Of the 75  successful  wells
drilled, 73 were development and two were exploratory.

For  additional  information  concerning  the  gas  exploration  and  production
segment,  see the  discussion on "Gas  Exploration  and  Production" in "Item 7.
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations" and for information with respect to net proved reserves, production,
productive wells and acreage, undeveloped acreage, drilling activities,  present
activities and drilling  commitments see "Note 17 to the Consolidated  Financial
Statements, Supplemental Gas and Oil Disclosures," included herein.

Domestic Pipelines and Gas Storage Facilities

We also own an approximate 20% interest in Iroquois Gas Transmission  System LP,
the partnership that owns a 375-mile pipeline that currently transports 946 MDTH
of Canadian gas supply daily from the New York-Canadian border to markets in the
Northeastern United States.  KeySpan is also a shipper on Iroquois and currently
transports up to 137 MDTH of gas per day.

We are also  participating  in the Islander East Pipeline Company LLC ("Islander
East"), an interstate pipeline joint venture with Duke Energy  Corporation.  The
joint venture  involves the  construction,  ownership and operation of a 50 mile
natural gas pipeline that will  transport 260 MDTH of gas supply daily from Nova
Scotia, Canada to growing markets in Connecticut, New York City and Long Island,
New  York.  Increasing  gas  transmission  capacity  is  necessary  to meet  the
increased  demand for natural gas in the  Northeast,  which  coincides  with the
growth  strategy  of our Gas  Distribution  business.  The  project  received  a
certificate of public  convenience  and necessity from the FERC  authorizing the
construction,  operation and maintenance of the interstate  natural gas pipeline
facilities in Connecticut and Long Island,  N.Y.  Islander East has obtained all
required  permits  in New  York  State  for the  construction  of the  facility.
However,  the State of  Connecticut  has issued a moratorium  on the issuance of
permits  relating  to the  construction  of energy  projects  until  June  2003.
Islander East has therefore been unable to obtain the necessary permits from the
State of Connecticut  at this time.  Islander East has also appealed a denial by
the State of  Connecticut  of the  coastal  zone  management  permit to the U.S.
Department  of Commerce and such appeal is currently  pending.  Islander East is
projected to be in service by year end 2004.


                                       14
<PAGE>

We also have equity  investments  in two gas storage  facilities in the State of
New York: Honeoye Storage  Corporation and Steuben Gas Storage Company. We own a
52% interest in Honeoye,  an underground gas storage  facility which provides up
to 4.8  billion  cubic  feet of  storage  service  to New York and New  England.
Additionally, we own 34% of a partnership that has a 50% interest in the Steuben
facility that  provides up to 6.2 billion  cubic feet of storage  service to New
Jersey and Massachusetts.

On December 12, 2002, we acquired Algonquin LNG, LP, the owner and operator of a
600,000  barrel  liquefied  natural gas ("LNG")  storage and receiving  facility
located in  Providence,  Rhode Island,  from Duke Energy for  approximately  $28
million. Boston Gas Company is the facility's largest customer and contracts for
more than  half of its  storage.  The  facility,  renamed  KeySpan  LNG,  LP, is
regulated by the FERC.

Our   investments  in  domestic   pipelines  and  gas  storage   facilities  are
complimentary to our Gas Distribution and Electric  Services  businesses in that
they provide energy infrastructure to support the growth of these businesses. To
the extent that opportunities  become available for expanding our investments in
these types of Energy  Investments,  KeySpan  will  continue  to  consider  such
investments as strategic.

Midstream Natural Gas Processing Activities in Canada

We also own 100% of KeySpan Canada, a company with natural gas processing plants
and  gathering  facilities  located  in Western  Canada.  In  October  2000,  we
purchased the remaining 50% interest in KeySpan Canada from our former  partner,
Gulf Canada  Resources  Limited.  The assets include  interests in 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.
Additionally,  KeySpan owns an  approximate  20% interest in Taylor NGL LP which
owns and operates two extraction  plants,  one located in British Columbia,  and
one in Alberta,  Canada. We also consider our Canadian operations to be non-core
assets and are also evaluating strategies to divest or monetize these assets.

Natural Gas Distribution and Pipeline Activities in the United Kingdom

We own a 50% interest in Premier  Transmission  Limited and a 24.5%  interest in
Phoenix  Natural Gas Limited  both in  Northern  Ireland.  Premier is an 84-mile
pipeline  to  Northern   Ireland  from  southwest   Scotland  that  has  planned
transportation capacity of approximately 300 MDTH of gas supply daily to markets
in Northern  Ireland.  Phoenix is a gas distribution  system serving the City of
Belfast,  Northern Ireland.  KeySpan also considers these assets non-core and is
evaluating the possible divestiture or monetization of these assets.

Marine Transportation Activities - Discontinued Operations

Our marine transportation subsidiary, Midland Enterprises, Inc. ("Midland") that
was acquired as part of the Eastern  acquisition was divested and its operations
discontinued.  We were required by the SEC to divest this subsidiary by November
8, 2003, as its operations were determined not to be functionally related to our
core utility operations as required by PUHCA. On July 2, 2002, we announced that
we  closed  the sale of  Midland  to a  subsidiary  of  Ingram  Industries  Inc.
("Ingram") and we received net proceeds of  approximately  $175 million from the
sale. See Note 9 "Discontinued  Operations," for further information on the sale
of our marine transportation business.

For additional  information  concerning the Energy Investments  segment, see the
discussion  on "Energy  Investments"  in "Item 7,  Management's  Discussion  and
Analysis of Financial Condition and Results of Operations" contained herein.

                         Environmental Matters Overview

KeySpan's  ordinary business  operations  subject it to regulation in accordance
with various federal,  state and local laws, rules and regulations  dealing with
the  environment,   including  air,  water,  and  hazardous  substances.   These
requirements  govern both our normal,  ongoing operations and the remediation of
impacted properties historically used in utility operations. Potential liability
associated  with our  historical  operations  may be imposed  without  regard to
fault, even if the activities were lawful at the time they occurred.


                                       15
<PAGE>


Except as set forth below, or in Note 7 to the Consolidated Financial Statements
"Contractual Obligations and Contingencies - Environmental Matters," no material
proceedings  relating to  environmental  matters have been  commenced or, to our
knowledge,  are  contemplated  by any  federal,  state or local  agency  against
KeySpan,  and we are not a defendant in any material  litigation with respect to
any matter  relating to the protection of the  environment.  We believe that our
operations  are in  substantial  compliance  with  environmental  laws  and that
requirements  imposed  by  environmental  laws are not likely to have a material
adverse impact upon us. We are also pursuing claims against  insurance  carriers
and  potentially   responsible  parties  which  seek  the  recovery  of  certain
environmental  costs  associated  with  the  investigation  and  remediation  of
contaminated  properties.  We believe that  investigation  and remediation costs
prudently  incurred  at  facilities  associated  with  utility  operations,  not
recoverable  through insurance or some other means, will be recoverable from our
customers.

Air. The Federal Clean Air Act ("CAA")  provides for the regulation of a variety
of air  emissions  from new and existing  electric  generating  plants.  We have
submitted timely applications for permits in accordance with the requirements of
Title V of the 1990  amendments  to the CAA.  Final permits have been issued for
all of our  electric  generating  facilities.  The  permits  allow our  electric
generating  plants to continue to operate  without  any  additional  significant
expenditures, except as described below.

Our generating  facilities are located within a CAA severe ozone  non-attainment
area,  and are  subject  to  Phase  I, II and  III  NOx  reduction  requirements
established  under the Ozone  Transportation  Commission  ("OTC")  memorandum of
understanding. Our investments in boiler combustion modifications and the use of
natural  gas  firing  systems at our steam  electric  generating  stations  have
enabled us to achieve the emission  reductions  required under Phase I and II of
the  OTC  memorandum  in a  cost-effective  manner.  We  are  required  to be in
compliance  with the  Phase III  reduction  requirements  of the OTC  memorandum
effective  May 1,  2003.  We expect to achieve  such  emission  reductions  in a
cost-effective  manner  through the  completion  of low NOx  combustion  control
systems,  the use of  natural  gas fuel and the  purchases  of  allowances  when
necessary.  Expenditures  for  combustion  control  systems and natural gas fuel
capability additions to address NOx emission reductions begun in 2002 and ending
in 2003 are expected to be between $10 million and $15 million.

Water.  The Federal  Clean Water Act provides for  effluent  limitations,  to be
implemented  by a permit  system,  to regulate the discharge of pollutants  into
United  States  waters.  We  possess  permits  for our  generating  units  which
authorize  discharges  from  cooling  water  circulating  systems  and  chemical
treatment  systems.  These permits are renewed from time to time, as required by
regulation.  Additional capital expenditures  associated with the renewal of the
surface water discharge permits for our power plants may be required by the DEC.
We are currently  monitoring impacts of our discharges on aquatic resources,  in
consultation  with the DEC. Until our monitoring  obligations  are completed and
proposed  changes  to the  Environmental  Protection  Agency  regulations  under
Section 316 of the Clean Water Act are  finalized,  the need for and the cost of
equipment upgrades, if any, cannot be determined.

Land.  The  Federal  Comprehensive  Environmental  Response,   Compensation  and
Liability Act of 1980 and certain similar state laws (collectively  "Superfund")
impose liability,  regardless of fault, upon generators of hazardous  substances
for costs associated with remediating  contaminated  property.  In the course of
our business operations, we generate materials which, after disposal, may become
subject  to  Superfund.  From  time to  time,  we have  received  notices  under
Superfund  concerning  possible  claims with  respect to sites  where  hazardous
substances  generated by KeySpan and other potentially  responsible parties were
allegedly disposed.  The cost of these claims is not presently determinable but,
if actually imposed on us, may be material to our financial  condition,  results
of operations or cash flows.

KeySpan has identified  certain  manufactured gas plant ("MGP") sites which were
historically   owned  or  operated  by  its  subsidiaries  (or  such  companies'
predecessors).  Operations at these sites between the mid 1800s to mid 1900s may
have  resulted in the release of hazardous  substances.  For a discussion on our
MGP sites and further information  concerning  environmental matters, see Note 7
to  the  Consolidated   Financial  Statements,   "Contractual   Obligations  and
Contingencies - Environmental Matters."


                                       16
<PAGE>

Competition, Regulation and Rate Matters

Competition

Over the last  several  years,  the  natural  gas and  electric  sectors  of the
regulated  energy  industry have undergone  significant  change as market forces
moved  towards   replacing  or   supplementing   rate  regulation   through  the
introduction  of competition.  A significant  number of natural gas and electric
utilities  reacted to the changing  structure of the energy industry by entering
into business combinations, with the goal of reducing common costs, gaining size
to better withstand  competitive  pressures and business  cycles,  and attaining
synergies  from  the   combination  of  operations.   We  engaged  in  two  such
combinations,  the  KeySpan/LILCO  transaction  in1998  and  our  November  2000
acquisition of Eastern and EnergyNorth.  For further  information  regarding the
gas and electric industry, see "Item 7. Management's  Discussion and Analysis of
Financial Condition and Results of  Operation-Regulatory  Issues and Competitive
Environment."

Additionally,  our  non-utility  subsidiaries  engaged  in the  Energy  Services
business compete with other mechanical,  HVAC, and engineering companies, and in
New Jersey are faced with  competition  from the  regulated  utilities  that are
still able to offer appliance repair and protection services.

Regulation

Public utility holding companies,  like KeySpan,  are regulated by the SEC under
PUHCA and to some extent by state utility  commissions through the regulation of
corporate,  financial and affiliate activities of public utilities.  Our utility
subsidiaries  are subject to  extensive  federal and state  regulation  by state
utility  commissions,  FERC and the SEC.  Our gas and  electric  public  utility
companies  are  subject  to either  or both  state and  federal  regulation.  In
general,  state public utility commissions,  such as the New York Public Service
Commission ("NYPSC"),  the Massachusetts  Department of  Telecommunications  and
Energy  ("DTE") and the New  Hampshire  Public  Utilities  Commission  ("NHPUC")
regulate the provision of retail  services,  including the distribution and sale
of natural gas and  electricity  to  consumers.  The FERC  regulates  interstate
natural gas transportation and electric transmission,  and has jurisdiction over
certain wholesale natural gas sales and wholesale electric sales.

In  addition,  our  non-utility  subsidiaries  are subject to a wide  variety of
federal,  state and local  laws,  rules and  regulations  with  respect to their
business activities,  including but not limited to those affecting public sector
projects,   environmental  and  labor  laws  and  regulations,  state  licensing
requirements,  as well as state laws and regulations  concerning the competitive
retail commodity supply.

State Utility Commissions

Our regulated  utility  subsidiaries are subject to regulation by the NYPSC, DTE
and NHPUC. The NYPSC regulates KEDNY and KEDLI,  and indirectly  KeySpan itself,
through  conditions  that were included in the NYPSC order  authorizing the 1998
KeySpan/LILCO transaction. Those conditions address the manner in which KeySpan,
its service company  subsidiaries and its unregulated  subsidiaries may interact
with KEDNY and KEDLI.  The NYPSC also  regulates  the  safety,  reliability  and
certain financial  transactions of our Long Island generating facilities and our
Ravenswood generating facility under a lightened regulatory standard.  Our KEDNE
subsidiaries are subject to regulation by the DTE and NHPUC. Our Energy Services
subsidiaries  which  engage in the retail sale of gas and  electricity  are also
subject to regulation by the NYPSC and the New Jersey Board of Public Utilities.
For further  information  regarding the state  regulatory  commissions,  see the
discussion  in  "Item 7.  Management's  Discussion  and  Analysis  of  Financial
Condition and Results of Operations - Regulation and Rate Matters."

Federal Energy Regulatory Commission

The FERC regulates the sale of electricity at wholesale and the  transmission of
electricity  in interstate  commerce as well as certain  corporate and financial
activities  of companies  that are engaged in such  activities.  The Long Island
generating facilities and the Ravenswood facility are subject to FERC regulation
based on their wholesale energy  transactions.  In 1998,  LIPA,  KeySpan and the
Staff of FERC stipulated to a five-year rate plan for the Long Island generating
facilities  with  agreed-upon  yearly  adjustments,  which have been approved by
FERC.  Our  Ravenswood  facility's  rates  are  based  on  a  market-based  rate
application  approved by FERC. The rates that our Ravenswood facility may charge


                                       17
<PAGE>

are subject to  mitigation  measures due to market power  concerns of FERC.  The
mitigation  measures are administered by the NYISO.  FERC retains the ability in
future  proceedings,  either on its own  motion or upon a  complaint  filed with
FERC,  to modify the  Ravenswood  facility's  rates,  as well as the  mitigation
measures, if FERC concludes that it is in the public interest to do so.

KeySpan  currently  bids and sells the energy,  capacity and ancillary  services
from the Ravenswood  facility  through the energy market  operated by the NYISO.
For information  concerning the NYISO, see "Item 7. Management's  Discussion and
Analysis of Financial Condition and Results of  Operation-Regulatory  Issues and
Competitive Environment."

The FERC also has  jurisdiction to regulate certain natural gas sales for resale
in  interstate  commerce,  the  transportation  of  natural  gas  in  interstate
commerce,   and,  unless  an  exemption  applies,   companies  engaged  in  such
activities.  The natural gas distribution  activities of KEDNY, KEDLI, KEDNE and
certain related intrastate gas transportation  functions are not subject to FERC
jurisdiction. However, to the extent that KEDNY, KEDLI or KEDNE purchase or sell
gas for resale in interstate  commerce,  such  transactions  are subject to FERC
jurisdiction  and have been  authorized by the FERC.  Our interests in Iroquois,
Honeoye,  Steuben and Algonquin LNG are also fully  regulated by FERC as natural
gas companies.

Securities and Exchange Commission

As a  result  of the  acquisition  of  Eastern  and  EnergyNorth,  we  became  a
registered holding company under PUHCA.  Therefore,  our corporate and financial
activities  and  those  of our  subsidiaries,  including  their  ability  to pay
dividends to us, are subject to regulation by the SEC. Under our holding company
structure,  we have no independent operations or source of income of our own and
conduct  substantially all of our operations  through our subsidiaries and, as a
result,  we  depend  on  the  earnings  and  cash  flow  of,  and  dividends  or
distributions  from, our subsidiaries to provide the funds necessary to meet our
debt and  contractual  obligations.  Furthermore,  a substantial  portion of our
consolidated  assets,  earnings and cash flow is derived from the  operations of
our regulated  utility  subsidiaries,  whose legal authority to pay dividends or
make other  distributions  to us is subject to  regulation  by state  regulatory
authorities.  For additional  information concerning regulation by the SEC under
PUHCA see the discussion under the heading  "Securities and Exchange  Commission
Regulation"  contained  in "Item 7.  Management's  Discussion  and  Analysis  of
Financial Condition and Results of Operations" contained herein.

Foreign Regulation

KeySpan's foreign operations in Northern Ireland,  conducted through Premier and
Phoenix, are subject to licensing by the Northern Ireland Department of Economic
Development  and  regulation by the U.K.  Department of Trade and Industry (with
respect to the subsea and  on-land  portions of the  Premier  pipeline)  and the
Northern Ireland Director General,  Office for the Regulation of Electricity and
Gas (with respect to the Northern  Ireland  portion of the Premier  pipeline and
Phoenix's  operations  generally).  The licenses  establish  mechanisms  for the
establishment of rates for the conveyance and transportation of natural gas, and
generally  may not be revoked  except  upon long- term  notice.  Charges for the
supply of gas by Phoenix are largely  unregulated unless a determination is made
of an absence of competition.

KeySpan's  assets in Canada are subject to  regulation  by Canadian  federal and
provincial  authorities.  Such regulatory authorities license various aspects of
the facilities and pipeline systems as well as regulate safety,  operational and
environmental  matters and certain  changes in such  facilities'  and pipelines'
capacities and operations.

Risks Related To Our Business

We are a Holding Company, and We and Our Subsidiaries are Subject to Federal
and/or State Regulation Which Limits Our Financial Activities, Including the
Ability of Our Subsidiaries to Pay Dividends and Make Distributions to Us


                                       18
<PAGE>

We are a holding company  registered under PUHCA with no business  operations or
sources  of income of our own.  We conduct  all of our  operations  through  our
subsidiaries  and  depend on the  earnings  and cash flow of, and  dividends  or
distributions  from, our subsidiaries to provide the funds necessary to meet our
debt and  contractual  obligations  and to pay  dividends  on our common  stock.
Because  we are a  registered  holding  company,  our  corporate  and  financial
activities  and  those  of our  subsidiaries,  including  their  ability  to pay
dividends to us from unearned  surplus,  are subject to PUHCA and  regulation by
the SEC.

In addition, a substantial portion of our consolidated assets, earnings and cash
flow is derived from the operation of our regulated utility subsidiaries,  whose
legal authority to pay dividends or make other distributions to us is subject to
regulation by the utility regulatory commissions of New York,  Massachusetts and
New  Hampshire.  Pursuant  to New York Public  Service  Commission  orders,  the
ability of KeySpan  Energy  Delivery  New York,  or KEDNY,  and  KeySpan  Energy
Delivery Long Island, or KEDLI, to pay dividends to us is conditioned upon their
maintenance of a utility capital  structure with debt not exceeding 55% and 58%,
respectively,  of  total  utility  capitalization.  In  addition,  the  level of
dividends  paid by both  utilities may not be increased from current levels if a
40 basis point penalty is incurred under a customer service performance program.
At the end of KEDNY's and KEDLI's  rate years  (September  30, 2002 and November
30, 2002,  respectively),  their ratios of debt to total utility  capitalization
were in compliance with the ratios set forth above.

PUHCA Also Limits Our  Business  Operations  and Our Ability to  Affiliate  with
Other Utilities

PUHCA,  in  addition  to  limiting  our  financial  activities,  also limits our
operations to a single integrated utility system, plus additional energy related
businesses,  regulates transactions between us and our subsidiaries and requires
SEC  approval  for  specified  utility  mergers and  acquisitions.  In its order
approving our acquisition of Eastern Enterprises and EnergyNorth,  Inc., the SEC
reserved  jurisdiction  on its  determination  of  whether  the  companies  that
comprise our energy  services  business  can be  classified  as  'energy-related
companies' and therefore retainable under existing SEC precedent.  We are unable
to predict  whether the SEC will authorize the retention of all or some of these
companies or the impact its determination  will have on our financial  condition
or results of operations.

The SEC is currently  conducting a routine audit of our  operations to determine
compliance  with PUHCA,  and while no issues have been brought to our  attention
that we believe to be material,  we can provide no assurances as to the ultimate
findings of the audit or their potential impact on our operations.

Our Gas Distribution and Electric Services  Businesses May Be Adversely Affected
by Changes in Federal and State Regulation

The regulatory  environment  applicable to our gas distribution and our electric
services  businesses has undergone  substantial changes in recent years, on both
the federal and state  levels.  These  changes have  significantly  affected the
nature of the gas and electric  utility and power  industries  and the manner in
which their participants conduct their businesses.  Moreover,  existing statutes
and regulations may be revised or reinterpreted, new laws and regulations may be
adopted or become applicable to us or our facilities, and future changes in laws
and  regulations  may  affect our gas  distribution  and our  electric  services
businesses in ways that we cannot predict.

In addition,  our operations are subject to extensive government  regulation and
require numerous permits, approvals and certificates from various federal, state
and local  governmental  agencies.  Some of our revenues in our Gas Distribution
and Electric  Services  segments are directly  dependent on rates established by
federal  or state  regulatory  authorities,  and any  change in these  rates and
regulatory structure could significantly impact our financial results. Increases
in utility costs other than gas, not  otherwise  offset by increases in revenues
or reductions in other expenses, could have an adverse effect on earnings due to
the time lag  associated  with  obtaining  regulatory  approval to recover  such
increased  costs  and  expenses,  and  the  uncertainty  of  whether  regulatory
commissions  will allow full recovery of and return on such increased  costs and
expenses.

Proposals  to  re-regulate  the  wholesale  power  market  have been made at the
federal level.  These  proposals,  and  legislative  and other  attention to the
electric power  industry could have a material  adverse effect on our strategies
and results of operations for our electric  services  business and our financial
condition.  In  particular,  we  sell  power  and  energy  from  our  Ravenswood
generating  facility into the New York Independent  System  Operator,  or NYISO,


                                       19
<PAGE>

energy market at market based rates,  subject to mitigation measures approved by
the Federal Energy Regulatory  Commission,  or FERC. The pricing for both energy
sales and services to the NYISO energy market is still  evolving and some of the
FERC's price mitigation  measures are subject to rehearing and possible judicial
review.

Our Risk Mitigation Techniques Such as Hedging and Purchase of Insurance May Not
Adequately Provide Protection

To lower our financial  exposure  related to commodity price  fluctuations,  our
marketing, trading and risk management operations routinely enter into contracts
to hedge a portion of our purchase and sale commitments,  weather  fluctuations,
electricity sales, natural gas supply and other commodities.  However, we do not
always cover the entire  exposure of our assets or our positions to market price
volatility  and the coverage will vary over time. To the extent we have unhedged
positions  or  our  hedging  procedures  do not  work  as  planned,  fluctuating
commodity prices could cause our sales and net income to be volatile.

Our  business  is  subject to many  hazards  from  which our  insurance  may not
adequately provide coverage. Therefore it is possible that our insurance may not
be  adequate  to cover all  losses  or  liabilities  that we might  incur in our
operations.  Unexpected  outage of  Ravenswood,  especially  in the  significant
summer  period,  could  materially  impact  our  financial  results.  Damage  to
pipelines,  equipment,  properties  and  people  caused  by  natural  disasters,
accidents, terrorism or other damage by third parties could exceed our insurance
coverage.  Although  we do have  insurance  to  protect  against  many of  these
contingent  liabilities,  this  insurance  is  capped  at  certain  levels,  has
self-insured retentions and does not provide coverage for all liabilities.

SEC Rules for Exploration and Production Companies May Require Us to Recognize a
Non-Cash Impairment Charge at the End of Our Reporting Periods

We use the full cost method of accounting for our investments in natural gas and
oil  properties.  These  investments  consist  of our  approximately  56% equity
interest in The Houston Exploration  Company, 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.
Under  the  full  cost  method,  all  costs  of  acquisition,   exploration  and
development  of natural gas and oil reserves are  capitalized  into a 'full cost
pool' as  incurred,  and  properties  in the pool are  depleted  and  charged to
operations  using the  unit-of-production  method based on production and proved
reserve  quantities.  To  the  extent  that  these  capitalized  costs,  net  of
accumulated depletion, less deferred taxes exceed the present value (using a 10%
discount  rate) of estimated  future net cash flows from proved  natural gas and
oil reserves and the lower of cost or fair value of unproved  properties,  those
excess costs are charged to  operations.  If a write-down is required,  it would
result in a charge to earnings but would not have an impact on cash flows.  Once
incurred,  an  impairment of gas  properties is not  reversible at a later date,
even if gas prices increase.

You May Not Be Able to Seek  Remedies  Against  Arthur  Andersen LLP, Our Former
Independent  Accountant,  with  Respect to Our  Financial  Statements  that were
Audited by Arthur Andersen

On June 15, 2002, Arthur Andersen LLP, our former  independent  certified public
accountant,  was convicted of federal  obstruction  of justice  arising from the
government's  investigation of Enron Corp. On April 5, 2002, we dismissed Arthur
Andersen  and  appointed  Deloitte  & Touche  LLP to  serve  as our  independent
certified  public  accountant for fiscal year 2002.  Arthur Andersen had audited
our  financial  statements  for the fiscal  years  ended  December  31, 2000 and
December  31, 2001.  Holders of our common  stock may have no  effective  remedy
against Arthur Andersen in connection  with a material  misstatement or omission
in those  financial  statements,  particularly in the event that Arthur Andersen
ceases to exist or  becomes  insolvent  as a result of the  conviction  or other
proceedings against it.

Our Operating Results May Fluctuate on a Seasonal and Quarterly Basis

Our gas distribution  business is a seasonal  business and is subject to weather
conditions.  We receive most of our gas  distribution  revenues in the first and
fourth  quarters  when demand for natural  gas usually  increases  due to colder
weather  conditions.  As a result,  we are  subject to  seasonal  variations  in
working  capital  because we purchase  most of our  natural gas  supplies in the


                                       20
<PAGE>

second and third  quarters and must increase our  borrowings in these periods to
finance these  purchases.  Accordingly,  our results of operations in the future
will  fluctuate  substantially  on  a  seasonal  basis.  In  addition,  our  New
England-based  gas  distribution   subsidiaries  do  not  benefit  from  weather
normalization  tariffs, and results from our Ravenswood  generating facility are
directly  correlated to the weather as the demand and price for the  electricity
it generates  increases during the summer. As a result,  fluctuations in weather
between  years may have a significant  effect on our results of  operations  for
these subsidiaries.

We Cannot  Predict  Whether  LIPA will  Exercise its Option to Purchase Our Long
Island Generating Assets and the Effect of that Purchase on Us

Under a Generation Purchase Right Agreement,  as amended,  entered into with the
Long Island  Power  Authority,  LIPA has the right to  purchase,  at fair market
value,  during the six month period beginning November 29, 2004, all of our Long
Island based generating assets that had been previously owned by the Long Island
Lighting  Company.  At this point in time, we cannot  predict  whether LIPA will
exercise its right to purchase the assets, nor can we estimate the effect on our
financial  condition  or  results of  operations  if LIPA were to  exercise  its
option.

A Substantial Portion of Our Revenues are Derived from Our Agreements with LIPA,
and No Assurances Can Be Made that These  Arrangements  Will Not Be Discontinued
at Some Point in the Future

We derive a substantial portion of our revenues in our electric services segment
from a series  of  agreements  with  LIPA  pursuant  to which we  manage  LIPA's
transmission  and  distribution   system  and  supply  the  majority  of  LIPA's
customers'  electricity needs. The agreements terminate at various dates between
May 28, 2006 and May 28, 2013 and at this time we can provide no assurance  that
any of the agreements will be renewed or extended or, if they were to be renewed
or extended, as to the terms and conditions thereof.

We Own Approximately 56% of The Houston Exploration  Company, and Our Results of
Operation are Therefore Subject to the Risks Affecting its Business

We own  approximately  56% of The Houston  Exploration  Company,  an independent
natural gas and oil producer. Therefore, our results of operations in our energy
investments  segment are subject to the same risks and uncertainties that affect
the operations of Houston Exploration.  In addition to the risks set forth under
the caption ' -- SEC rules for exploration and production  companies may require
us to  recognize  a  non-cash  impairment  charge  at the  end of our  reporting
periods,' these risks and uncertainties include:

          The  volatility of natural gas and oil prices.  If natural gas and oil
     prices decline,  the amount of natural gas and oil Houston  Exploration can
     economically produce may be reduced, which may result in a material decline
     in its revenue.

          The  potential  inability of Houston  Exploration  to meet its capital
     requirements.  If  Houston  Exploration  is  unable  to  meet  its  capital
     requirements  to fund,  develop,  acquire and  produce  natural gas and oil
     reserves, its oil and gas reserves will decline.

          Substantial    indebtedness.    Houston   Exploration's    outstanding
     indebtedness under its bank credit facility and the indenture governing its
     senior  subordinated  notes  contain  covenants  that require a substantial
     portion  of its cash  flow  from  operations  to be  dedicated  to its debt
     service obligations and impose other restrictions that limit its ability to
     borrow additional funds or dispose of assets. These restrictions may affect
     its  flexibility  in planning  for, and  reacting  to,  changes in business
     conditions.

          Estimates of proved  reserves  and future net revenue may change.  Any
     significant  variance from the assumptions used to estimate proved reserves
     or natural gas could result in the actual quantity of Houston Exploration's
     reserves  and  future  net cash flow being  materially  different  from the
     estimates in its reserve report.



                                       21
<PAGE>

A Decline  or an  Otherwise  Negative  Change in the  Ratings  or Outlook on Our
Securities  Could  Have a  Materially  Adverse  Impact on Our  Ability to Secure
Additional Financing on Favorable Terms

The rating  agencies  that rate our  securities  regularly  review our financial
condition  and  results of  operations.  We can provide no  assurances  that the
ratings or outlook on our securities will not be reduced or otherwise negatively
changed.  A negative  change in the ratings or outlook on our  securities  could
have a materially  adverse impact on our ability to secure additional  financing
on favorable terms.

Our Costs of Compliance with Environmental Laws are Significant, and the Cost of
Compliance with Future Environmental Laws Could Adversely Affect Us

Our operations are subject to extensive federal,  state and local  environmental
laws and regulations relating to air quality,  water quality,  waste management,
natural   resources  and  the  health  and  safety  of  our   employees.   These
environmental laws and regulations  expose us to costs and liabilities  relating
to our operations and our current and formerly owned properties. Compliance with
these  legal  requirements  requires  us to commit  significant  capital  toward
environmental  monitoring,  installation  of  pollution  control  equipment  and
permits at our facilities.  Costs of compliance with environmental  regulations,
and in  particular  emission  regulations,  could have a material  impact on our
electric services business and our results of operations and financial position,
especially  if  emission  limits  are  tightened,   more  extensive   permitting
requirements are imposed,  additional  substances become regulated or the number
and type of electric generating plants we operate increase.

In addition,  we are  responsible for the clean-up of  contamination  at certain
manufactured  gas  plant  ('MGP')  sites  and at other  sites  and are  aware of
additional MGP sites where we may have  responsibility for clean up costs. While
our gas rate  plans  generally  allow  for the  full  recovery  of the  costs of
investigation and remediation of MGP sites,  these rate recovery  mechanisms may
change in the  future.  To the extent  rate  recovery  mechanisms  change in the
future,  or if  additional  environmental  matters  arise in the  future  at our
currently  or  historically  owned  facilities,  at sites we may  acquire in the
future  or  at  third  party  waste  disposal  sites,   costs   associated  with
investigating  and remediating  these sites could have a material adverse effect
on our results of operations and financial condition.

Our  Businesses  are  Subject to  Competition  and General  Economic  Conditions
Impacting Demand for Services

Ravenswood,  our merchant generation plant, in our Electric Services segment, is
subject to  competition  that could  adversely  impact the market  price for the
electricity it produces.  Construction of new transmission facilities could also
cause  significant  changes to the market.  If  generation  and/or  transmission
facilities are constructed,  and/or the availability of our Ravenswood  facility
deteriorates,  then the  capacity and energy  sales  volumes  could be adversely
affected.  We  cannot  predict,   however,  when  or  if  new  power  plants  or
transmission  facilities will be built or the nature of the future New York City
energy requirements.

Competition 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, could
adversely  impact  our  financial  results  and the  value of those  businesses,
resulting in decreased  earnings as well as writedowns of the carrying  value of
those  businesses.  In addition,  competition in the fiber optics business could
negatively impact the value of this business.

Our Gas Distribution  segment faces competition with distributors of alternative
fuels and forms of  energy,  including  fuel oil and  propane.  Our  ability  to
continue  to  add  new  gas  distribution  customers  may  significantly  impact
financial results.  The gas distribution  industry has experienced a decrease in
consumption  per customer  over time  partially  due to increased  efficiency of
customers'  appliances.  Our Gas  Distribution  segment  is  dependent  upon the
ability to add new customers to our system in a cost-effective manner. While our
Long Island and New England  utilities have  significant  growth  potential,  we
cannot be sure new customers will continue to offset the decrease in consumption
of our  existing  customer  base.  There are a number of factors  outside of our
control that impact  whether a potential  customer  converts from an alternative
fuel to gas, including general economic factors impacting customers  willingness
to invest in new gas equipment.



                                       22
<PAGE>

Employee Matters

As of  December  31,  2002,  KeySpan  and  its  wholly  owned  subsidiaries  had
approximately 13,000 employees. Of that total,  approximately 5,850 employees in
our  regulated  companies are covered under  collective  bargaining  agreements.
KeySpan has not  experienced  any work  stoppage  during the past five years and
considers its relationship with employees, including those covered by collective
bargaining agreements, to be good.

Executive Officers of the Company

Certain  information  regarding executive officers of KeySpan and certain of its
subsidiaries is set forth below:

Robert B. Catell

Mr.  Catell,  age 66, has been a Director of KeySpan  since its  creation in May
1998. He was elected  Chairman of the Board and Chief Executive  Officer in July
1998.  He served as its  President  and Chief  Operating  Officer  from May 1998
through  July 1998.  Mr.  Catell  joined  KEDNY in 1958 and became an officer in
1974. He was elected Vice  President in 1977,  Senior Vice President in 1981 and
Executive Vice President in 1984. He was elected Chief Operating Officer in 1986
and  President in 1990.  Mr.  Catell  continued to serve as President  and Chief
Executive  Officer of KEDNY from 1991 through 1996, when he was elected Chairman
and Chief Executive Officer. In 1997, Mr. Catell was elected Chairman, President
and Chief Executive Officer of KEDNY and its parent KeySpan Energy Corporation.

Robert J. Fani

Mr. Fani, age 49, was elected President,  KeySpan Energy Assets and Supply Group
in January 2003. Mr. Fani joined KEDNY in 1976, and held a variety of management
positions  in  distribution,  engineering,  planning,  marketing,  and  business
development.  He was  elected  Vice  President  in 1992.  In 1997,  Mr. Fani was
promoted to Senior Vice President of Marketing and Sales for KEDNY.  In 1998, he
assumed  the  position  of Senior  Vice  President  of  Marketing  and Sales for
KeySpan.  In September  1999, he became Senior Vice President for Gas Operations
and was promoted to Executive Vice President in February 2000 and then President
of Energy  Services and Supply until  assuming his current  position in February
2003.

Wallace P. Parker Jr.

Mr.  Parker,  age 53,  was  elected  President,  Energy  Delivery  and  Customer
Relations Group, in January 2003. He had previously served as President, KeySpan
Energy  Delivery,  since June 2001,  and before  that served as  Executive  Vice
President of Gas  Operations  from  February  2000.  He joined KEDNY in 1971 and
served in a wide variety of management positions. In 1987 he was named Assistant
Vice President for marketing and  advertising  and was elected Vice President in
1990.  In 1994,  Mr.  Parker was  promoted  to Senior  Vice  President  of Human
Resources  and in August 1998 was  promoted to Senior  Vice  President  of Human
Resources of KeySpan.

John A. Caroselli

Mr.  Caroselli,  age 48, was  elected  Executive  Vice  President  of  Strategic
Services in October  2001 and is  responsible  for Brand  Management,  Strategic
Marketing,  Strategic  Planning,  Strategic  Performance,  and  E-business.  Mr.
Caroselli  came to  KeySpan in 2001 and  served at that time as  Executive  Vice
President of Corporate  Development.  Before joining KeySpan, Mr. Caroselli held
the  position of  Executive  Vice  President  of  Corporate  Development  at AXA
Financial. Prior to that, he held senior officer positions with Chase Manhattan,
Chemical Bank and  Manufacturers  Hanover Trust. He has extensive  experience in
brand  management,  marketing,   communications,   human  resources,  facilities
management, e-business and change management.


                                       23
<PAGE>

Gerald Luterman

Mr.  Luterman,  age 59 was elected  Executive Vice President and Chief Financial
Officer in February  2002.  He  previously  served as Senior Vice  President and
Chief  Financial  Officer since joining KeySpan in July 1999. He formerly served
as Chief Financial Officer of  barnesandnoble.com  and Senior Vice President and
Chief  Financial  Officer of Arrow  Electronics,  Inc. Prior to that,  from 1985
through 1996, he held  executive  positions  with  American  Express,  including
Executive  Vice  President  and Chief  Financial  Officer of the  Consumer  Card
Division from  1991-1996.  Mr.  Luterman has served on the Board of Directors of
The Houston Exploration Company since May 2000.

Anthony Nozzolillo

Mr.  Nozzolillo,  age 54, was  elected  Executive  Vice  President  of  Electric
Operations in February  2000. He previously  served as Senior Vice  President of
KeySpan's  Electric  Business Unit from December 1998 to January 2000. He joined
LILCO  in 1972  and held  various  positions,  including  Manager  of  Financial
Planning  and  Manager of Systems  Planning.  Mr.  Nozzolillo  served as LILCO's
Treasurer  from 1992 to 1994 and as Senior Vice  President  of Finance and Chief
Financial Officer from 1994 to 1998.

Lenore F. Puleo

Ms. Puleo,  age 49, was elected  Executive Vice President of Client  Services in
June 2000. She previously served as Senior Vice President of Customer  Relations
for KEDNY from May 1994 to May 1998,  and for  KeySpan  from May 1998 to January
2000.  She joined  KEDNY in 1974 and worked in  management  positions in KEDNY's
Accounting,  Treasury,  Corporate  Planning,  and Human Resources areas. She was
given  responsibility for the Human Resources Department in 1987 and was named a
Vice  President  in 1990.  Ms.  Puleo was  promoted to Senior Vice  President of
KEDNY's Customer Relations in 1994.

Nickolas Stavropoulos

Mr.  Stavropoulos,  age  44,  was  elected  Executive  Vice  President,  KeySpan
Corporation,  and President, KeySpan Energy Delivery New England, in April 2002;
prior to this he was Senior Vice President of sales and marketing in New England
since 2000. Prior to joining KeySpan, Mr. Stavropoulos was Senior Vice President
of marketing and gas resources for Boston Gas. Before joining Boston Gas, he was
Executive Vice President and Chief Financial  Officer for Colonial Gas. In 1995,
Mr.  Stavropoulos was elected Executive Vice President - Finance,  Marketing and
CFO, and assumed  responsibility  for all of  Colonial's  financial,  marketing,
information technology and customer service functions.

Steven L. Zelkowitz

Mr. Zelkowitz,  age 53, Executive Vice President, was named Chief Administrative
Officer,  with  responsibility  for  the  offices  of  General  Counsel,   Human
Resources,  Regulatory Affairs, Enterprise Risk Management, and administratively
for Internal  Auditing,  in January  2003.  Prior to that he served as Executive
Vice  President-Administration and Compliance since November 2002, and Executive
Vice President and General Counsel of KeySpan since July 2001. He joined KeySpan
as Senior Vice  President and Deputy  General  Counsel in October 1998,  and was
elected  Senior Vice  President  and General  Counsel in February  2000.  Before
joining  the  Company,  Mr.  Zelkowitz  practiced  law with Cullen and Dykman in
Brooklyn,  New York specializing in energy and utlity law and had been a partner
since  1984.  He served on the firm's  Executive  Committee  and was head of its
Corporate/Energy Department.


                                       24
<PAGE>

John J. Bishar, Jr.

Mr. Bishar, age 52, became Senior Vice President and General Counsel on November
1,  2002,  with  responsibility  for the Legal  Services  Business  Unit and the
Corporate  Secretary's Office.  Before joining KeySpan, Mr. Bishar practiced law
with Cullen and Dykman LLP. He was the  Managing  Partner from 1993 through 2002
and was a member of the  firm's  Executive  Committee.  From  1980 to 1987,  Mr.
Bishar was Vice  President,  General  Counsel and  Corporate  Secretary of LITCO
Bancorporation  of New York,  Inc. In 1987,  Mr.  Bishar  returned to Cullen and
Dykman  LLP as a partner  responsible  for the  firm's  commercial  lending  and
commercial   real  estate   lending   activities  for  a  variety  of  financial
institutions.

Joseph F. Bodanza

Mr. Bodanza, age 55, was elected Senior Vice President of Finance Operations and
Regulatory  Affairs in August 2001, and Chief Accounting Officer effective April
1,  2003.  Prior to his  appointment  he was  Senior  Vice  President  and Chief
Financial  Officer  of KEDNE.  Mr.  Bodanza  previously  served  as Senior  Vice
President of Finance and Management Information Systems and Treasurer of Eastern
Enterprise's Gas Distribution Operations.  Mr. Bodanza joined Boston Gas in 1972
and held a variety of positions in the  financial  and  regulatory  areas before
becoming Treasurer in 1984. He was elected Vice President and Treasurer in 1988.

John F. Haran

Mr. Haran, age 52, was elected Senior Vice President of gas operations for KEDNY
and KEDLI in April 2002. Mr. Haran joined The Brooklyn Union Gas Company in 1972
and has held management positions in operations,  engineering, and marketing and
sales.  He was named Vice  President of KEDNY gas operations in 1996 and in 2000
moved to the position of Vice President of KEDLI gas operations.

David J. Manning

Mr.  Manning,  age 52, was elected Senior Vice President of KeySpan's  Corporate
Affairs  group in April  1999.  Before  joining  KeySpan,  Mr.  Manning had been
President of the Canadian  Association of Petroleum  Producers  since 1995. From
1993 to 1995,  he was Deputy  Minister  of Energy for the  Province  of Alberta,
Canada.  From 1988 to 1993,  he was Senior  International  Trade Counsel for the
Government of Alberta,  based in New York City. Previously he was in the private
practice of law in Canada.

H. Neil Nichols

Mr.  Nichols,  age 65, was elected Senior Vice President of KeySpan's  Corporate
Development  and Asset  Management  division  in March  1999.  He also serves as
President of KeySpan  Energy  Development  Corporation  ("KEDC"),  a position to
which he was elected in March 1998. KEDC is a wholly owned subsidiary of KeySpan
responsible for our Energy Investments segment. Since February 1999, Mr. Nichols
also has responsibility for KeySpan Energy Trading Services, LLC, which provides
fuel-procurement  management and energy-trading  services as agent for LIPA. Mr.
Nichols  joined  KeySpan  in  1997  as a  broad-based  negotiator  and  business
strategist with  comprehensive  finance and treasury  experience in domestic and
international  markets.  Prior to joining KeySpan,  Mr. Nichols was an owner and
president of Corrosion Interventions, Ltd. in Toronto, Canada. He also served as
Chief Financial Officer and Executive Vice President with TransCanada PipeLines.

Colin P. Watson

Mr.  Watson,  age 51, was named Senior Vice  President  of  KeySpan's  Strategic
Marketing and E-Business  division effective March 1, 2000. He previously served
as Vice  President of Strategic  Marketing  from May 1998 until his promotion to
Senior Vice  President.  Mr.  Watson  joined KEDNY in 1997 as Vice  President of
Strategic  Marketing.  From 1973 to 1997,  he held  several  positions at NYNEX,
including  Vice  President of General  Business  Sales and Managing  Director of
worldwide operations.


                                       25
<PAGE>

Elaine Weinstein

Ms.  Weinstein,  age 56, was named  Senior Vice  President  of  KeySpan's  Human
Resources  division in November 2000. She previously served as Vice President of
Staffing and  Organizational  Development  since September  1998.  Prior to that
time, Ms.  Weinstein was General Manager of Employee  Development  since joining
KeySpan in 1995. Prior to 1995, Ms. Weinstein was Vice President of Training and
Organizational Development at Merrill Lynch.

Kamal Dua

Mr. Dua, age 43, was elected Vice  President  and General  Auditor in June 2002.
Prior  to  joining  KeySpan,  he was  Assistant  Corporate  Controller  for AT&T
Corporation responsible for providing Decision Support services to the Corporate
Functions and the CFO for the Shared  Services.  Prior to joining AT&T,  Mr. Dua
held executive level  positions in the Finance and Internal Audit  Department of
Verizon  Corporation  (formerly  Bell  Atlantic).  Mr. Dua has also held  Senior
Manager and Manager level positions with  PriceWaterhouseCoopers  LLP, Chartered
Accountants, BDO Seidman LLP, CPAs and Mitchell Titus & Co LLP, CPAs.

Ronald S. Jendras

Mr. Jendras,  age 55, was named Vice President,  Controller and Chief Accounting
Officer of KeySpan in August 1998. He joined KEDNY in 1969 and held a variety of
positions in the  Accounting  Department  before being named budget  director in
1973.  In 1983,  Mr.  Jendras  was  promoted  to  manager  of  KEDNY's  Rate and
Regulatory  Affairs  area,  and  in  1997,  was  named  general  manager  of the
Accounting Division.  Mr. Jendras has been Treasurer of KeySpan Foundation since
1998 and serves as a member of its Board of Directors.

Richard A. Rapp, Jr.

Mr. Rapp, age 44, serves as Vice President and Secretary of KeySpan Corporation,
a  position  he was  appointed  to in June 2000.  On March 7, 2003,  he was also
elected Senior Vice  President of KeySpan Energy Supply,  Inc. Prior to March 7,
2003,  Mr Rapp also served as Deputy  General  Counsel since  February  2000. He
joined LILCO in 1984 and has held various  positions in the Legal Departments of
LILCO, and since 1998, KeySpan, including Assistant General Counsel.

Michael J. Taunton

Mr. Taunton,  age 46, has been KeySpan's Vice President and Treasurer since June
2000.  Prior to that time,  he served as Vice  President  of Investor  Relations
since September 1998. He joined KEDNY in 1975 and held a succession of positions
in Accounting,  Customer Service, Corporate Planning, Budgeting and Forecasting,
Marketing and Sales, and Business Process Improvement.  During the KeySpan/LILCO
merger, Mr. Taunton  co-managed the day-to-day  transition process of the merger
and then  served on the  Transition  Team  during  the  acquisition  of  Eastern
Enterprises (now known as KeySpan New England, LLC).

Item 2.  Properties

Information with respect to KeySpan's material properties used in the conduct of
its business is set forth in, or  incorporated  by reference  in, Item 1 hereof.
Except where otherwise specified,  all such properties are owned or, in the case
of certain rights of way used in the conduct of its gas  distribution  business,
held pursuant to municipal  consents,  easements or long-term leases, and in the
case of gas and oil properties, held under long-term mineral leases. In addition
to the information set forth therein with respect to properties utilized by each
business segment, KeySpan leases the executive headquarters located in Brooklyn,
New York.  In  addition,  we lease  other  office  and  building  space,  office
equipment,  vehicles and power operated  equipment.  Our properties are adequate
and suitable to meet our current and expected business  requirements.  Moreover,
their  productive  capacity and  utilization  meet our needs for the foreseeable
future.  KeySpan  continually  examines its real property and other property for
its contribution and relevance to our businesses and when such properties are no
longer productive or suitable,  they are disposed of as promptly as possible. In
the case of leased office space,  we  anticipate  no  significant  difficulty in
leasing  alternative  space at reasonable  rates in the event of the expiration,
cancellation or termination of a lease.


                                       26
<PAGE>

Item 3.  Legal Proceedings

See Note 7 to the Consolidated  Financial Statements,  "Contractual  Obligations
and Contingencies - Legal Matters."

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

No matters  were  submitted to a vote of the  security  holders  during the last
quarter of the 12 months ended December 31, 2002.



                                     PART II

Item 5.  Market for Registrant's Common Equity and Related Stockholder Matters

KeySpan's common stock is listed and traded on the New York Stock Exchange and
the Pacific Stock Exchange under the symbol "KSE." As of March 1, 2003, there
were approximately 70,213 registered record holders of KeySpan's common stock.
The following table sets forth, for the quarters indicated, the high and low
sales prices and dividends declared per share for the periods indicated:

2002                     High              Low               Dividends Per Share
First Quarter           $36.72            $30.01            $0.445
Second Quarter          $37.45            $34.35            $0.445
Third Quarter           $38.19            $27.41            $0.445
Fourth Quarter          $37.15            $30.75            $0.445

2001                     High              Low               Dividends Per Share
First Quarter           $41.94            $34.20            $0.445
Second Quarter          $41.10            $35.75            $0.445
Third Quarter           $37.20            $29.10            $0.445
Fourth Quarter          $35.35            $31.53            $0.445





                                       27
<PAGE>

The following table sets forth securities authorized for issuance under equity
compensation plans for the year ended December 31, 2002:
<TABLE>
<CAPTION>
                                                                                                   Number of securities
                               Number of securities                                                Remaining available for
                               to be issued                   Weighted-average                     future issuance under
                               upon exercise of               exercise price of                    equity compensation plans
                               outstanding options,           outstanding options,                 (excluding securities
Plan category                  warrants and rights            warrants and rights,                 reflected in column (a))
-------------                  -------------------            --------------------                 -------------------------
                                       (a)                            (b)                                     (c)
<S>                              <C>                             <C>                                     <C>
Equity compensation                9,549,039(1)                   $25.37                                   7,031,761
   plans approved by
   security holders.....

Equity compensation                   44,293(2)                      N/A                                          (3)
   plans not approved
   by security holders..
           Total.........          9,593,332                      $25.37                                   7,031,761
</TABLE>
(1)  Includes  grants of options and  restricted  stock  pursuant  to  KeySpan's
     Long-Term Performance Incentive  Compensation Plan, as amended, and options
     granted  pursuant to the Brooklyn  Union  Long-Term  Performance  Incentive
     Compensation  Plan and  options  granted  pursuant  to Eastern  Enterprises
     Long-Term  Performance  Incentive  Compensation  Plans,  as well as 328,000
     shares of Common Stock issued pursuant to the Stock Plan.
(2)  Represents  Deferred Stock Units issued pursuant to the Officers'  Deferred
     Stock Unit Plan.
(3)  There is no set  limit on the  number  of  Deferred  Stock  Units  issuable
     pursuant to the Officers'  Deferred Stock Unit Plan or the KeySpan Services
     Inc. Officers' Deferred Stock Unit Plan.

Directors' Deferred Compensation Plan

The Directors'  Deferred  Compensation Plan provides all non-employee  directors
with the opportunity to defer any portion of their cash compensation received as
directors,  up to  100%,  in  exchange  for  Common  Stock  equivalents  or cash
equivalents. Common Stock equivalents are valued by utilizing the average of the
high and low price per share of KeySpan common stock on the first trading day of
the month following the month in which contributions are received. Dividends are
paid on Common Stock  equivalents  in the same  proportion as dividends  paid on
Common  Stock.   Compensation  not  deferred  and  exchanged  for  Common  Stock
equivalents,  may be deferred into a cash account bearing  interest at the prime
rate.  Upon  retirement,  death or  termination  of service as a  director,  all
amounts in a director's  Common  Stock  equivalent  account  and/or cash account
shall,  at the director's  election,  (i) be paid in a lump sum in cash; (ii) be
deferred  for up to five  years;  and/or  (iii) be paid in the  number of annual
installments,  up to ten, specified by the director.  The non-employee directors
are not entitled to benefits under any KeySpan retirement plan.

Officers' Deferred Stock Unit Plan

The Officers'  Deferred Stock Unit Plan allows certain executives of the Company
and its wholly owned  subsidiaries to elect to defer between 10% to 50% of their
annual cash bonus award and purchase deferred stock units ("DSUs"),  which track
the performance of the Company's  Common Stock but do not possess voting rights.
Executives  also  receive a 20% match by the  Company on the amount  deferred in
each year.  The DSUs must be deferred until  retirement or  resignation  and are
payable in Common  Stock.  The match on the  deferral is also  payable in Common
Stock upon  retirement or in the event of an  executive's  disability,  death or
upon change of control.  The match is forfeited in the event of the  executive's
resignation prior to retirement.

KeySpan Services Inc. Officers' Deferred Stock Unit Plan

The KeySpan  Services Inc.  Officers'  Deferred  Stock Unit Plan allows  certain
officers of KeySpan Services Inc.and its wholly owned subsiadiries,  to elect to
defer  between 10% to 50% of their  annual cash bonus  award and  purchase  DSUs
which track the  performance  of the  Company's  Common Stock but do not possess
voting rights.  Executives also receive a 20% match by the Company on the amount
deferred in each year. The DSUs must be deferred until retirement or resignation
and are payable in Common  Stock.  The match on the  deferral is also payable in
Common Stock upon retirement or in the event of an executive's disability, death
or  upon  change  of  control.  The  match  is  forfeited  in the  event  of the
executive's resignation prior to retirement.

                                       28
<PAGE>

Item 6. Selected Financial Data
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                        Nine Months
                                                                           Year Ended December 31,                      December 31,
(In Thousands of Dollars, Except Per Share Amounts)       2002           2001            2000            1999               1998
                                                   --------------------------------------------------------------------------------
Income Summary
<S>                                                   <C>             <C>             <C>             <C>               <C>
Revenues
     Gas Distribution                                 $ 3,163,761    $ 3,613,551     $ 2,555,785     $ 1,753,132         $ 856,172
     Electric Services                                  1,421,043      1,421,079       1,444,711         861,582           408,305
     Electric Distribution                                      -              -               -               -           330,011
     Energy Services                                      938,761      1,100,167         770,110         186,529            63,064
     Energy Investments and other                         447,101        498,318         310,096         153,370            70,929
                                                   --------------------------------------------------------------------------------
Total revenues                                          5,970,666      6,633,115       5,080,702       2,954,613         1,728,481
Operating expenses
     Purchased gas for resale                           1,653,273      2,171,113       1,408,680         744,432           331,690
     Fuel and purchased power                             385,059        538,532         460,841          17,252            91,762
     Operations and maintenance                         2,101,897      2,114,759       1,659,736       1,091,166           777,678
     Depreciation, depletion and amortization             514,613        559,138         330,922         253,440           254,859
     Early retirement and severance charges                     -              -          65,175               -            64,635
     Operating taxes                                      410,651        448,924         421,936         366,154           257,124
                                                   --------------------------------------------------------------------------------
Operating income                                          905,173        800,649         733,412         482,169           (49,267)
Other income (deductions)                                (282,429)      (346,264)       (213,400)        (87,196)         (177,460)
                                                   --------------------------------------------------------------------------------
Income (loss) before income taxes                         622,744        454,385         520,012         394,973          (226,727)
Income taxes (credits)                                    225,394        210,693         217,262         136,362           (59,794)
                                                   --------------------------------------------------------------------------------
Earnings (loss) from continuing operations                397,350        243,692         302,750         258,611          (166,933)
                                                   --------------------------------------------------------------------------------
Discontinued Operations
    Income (loss) from operations, net of tax              (3,356)        10,918          (1,943)              -                 -
    Loss on disposal, net of tax                          (16,306)       (30,356)              -               -                 -
                                                   --------------------------------------------------------------------------------
Loss from discontinued operations                         (19,662)       (19,438)         (1,943)              -                 -
                                                   --------------------------------------------------------------------------------
Net Income (Loss)                                         377,688        224,254         300,807         258,611          (166,933)
Preferred stock dividend requirements                       5,753          5,904          18,113          34,752            28,604
                                                   --------------------------------------------------------------------------------
Earnings (loss) for Common Stock                        $ 371,935      $ 218,350       $ 282,694       $ 223,859        $ (195,537)
                                                   ================================================================================
Financial Summary
Basic earnings (loss) per share ($)                          2.63           1.58            2.10            1.62             (1.34)
Cash dividends declared per share ($)                        1.78           1.78            1.78            1.78              1.19
Book value per share, year-end ($)                          20.67          20.73           20.65           20.26             20.90
Market value per share, year-end ($)                        35.24          34.65           42.38           23.19             31.00
Shareholders, year end                                     78,281         82,300          86,900          90,500           103,239
Capital expenditures ($)                                1,161,456      1,059,759         925,257         725,670           676,563
Total assets ($)                                       12,614,306     11,789,606      11,307,465       6,730,691         6,895,102
Common shareholders' equity ($)                         2,944,592      2,890,602       2,815,816       2,712,325         3,022,908
Redeemable preferred stock ($)                                  -              -               -         363,000           363,000
Preferred stock ($)                                        83,849         84,077          84,205          84,339           447,973
Long-term debt ($)                                      5,224,081      4,697,649       4,116,441       1,682,702         1,619,067
Total capitalization ($)                                8,252,522      7,672,328       7,016,462       4,479,366         5,089,948
-----------------------------------------------------------------------------------------------------------------------------------
Utility Operating Statistics
Firm gas and transportation sales (MDTH)                  348,454        347,659         271,543         244,659            87,179
Other sales (MDTH)                                        209,002        188,037         126,372          85,773            38,088
Total active gas meters                                 2,523,974      2,499,170       2,483,730       1,628,497         1,610,202
</TABLE>

                                       29

<PAGE>

Item 7. Management's  Discussion and Analysis of Financial Condition and Results
of Operations

KeySpan Corporation (referred to herein 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  us the  fifth  largest  gas
distribution  company in the United States and the largest in the Northeast.  We
also own and operate electric  generating  plants in Nassau and Suffolk Counties
on Long  Island  and in  Queens  County  in New York  City  and are the  largest
investor owned generator in New York State. Under contractual  arrangements,  we
provide power,  electric  transmission  and distribution  services,  billing and
other customer services for approximately one million electric  customers of the
Long Island Power Authority ("LIPA").  KeySpan's other subsidiaries are involved
in gas and oil exploration and production; gas storage; wholesale and retail gas
and electric marketing;  appliance service; plumbing, heating,  ventilation, air
conditioning  and other mechanical  contracting  services;  large  energy-system
ownership, installation and management; engineering and consulting services; and
fiber optic  services.  We also invest and  participate  in the  development  of
natural gas pipelines,  natural gas processing plants, electric generation,  and
other energy-related  projects,  domestically and  internationally.  (See Note 2
"Business Segments" for additional information on each operating segment.)

Consolidated Summary of Results

Consolidated  earnings before interest and taxes ("EBIT") by segment, as well as
consolidated  earnings  available for common stock is set forth in the following
table for the periods indicated.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
                                                                    Year Ended December 31,
 (In Thousands of Dollars, Except Per Share Amounts)              2002       2001        2000
-------------------------------------------------------------------------------------------------
<S>                                                             <C>        <C>         <C>
 Gas Distribution                                                $524,311   $492,362    $367,226
 Electric Services                                                309,663    283,533     310,823
 Energy Services                                                  (10,377)  (143,492)     14,630
 Energy Investments                                               128,265    141,477     131,686
 Eliminations and other                                           (27,614)    33,975    (103,039)
                                                                  -------------------------------
 Earnings Before Interest Charges
    and Taxes                                                     924,248    807,855     721,326
 Interest charges                                                 301,504    353,470     201,314
 Income taxes                                                     225,394    210,693     217,262
                                                                  -------------------------------
 Earnings from Continuing Operations                              397,350    243,692     302,750
 Discontinued operations                                          (19,662)   (19,438)     (1,943)
                                                                  -------------------------------
 Net Income                                                       377,688    224,254     300,807
 Preferred stock dividends                                          5,753      5,904      18,113
                                                                  -------------------------------
 Earnings for Common Stock                                       $371,935   $218,350    $282,694
                                                                 ================================

 Basic Earnings per Share:
    Continuing operations                                        $   2.77   $   1.72    $   2.12
    Discontinued operations                                         (0.14)     (0.14)      (0.02)
-------------------------------------------------------------------------------------------------
                                                                 $   2.63   $   1.58    $   2.10
-------------------------------------------------------------------------------------------------
</TABLE>


                                       30

<PAGE>

As  indicated in the above  table,  earnings  from  continuing  operations  less
preferred  stock  dividends  for the year ended  December 31, 2002  increased by
$153.8  million,  or $1.05 per share  compared to the same  period in 2001.  The
increase  in  earnings  from  continuing   operations   reflects  the  following
significant   events  which  are  discussed  in  more  detail  below:   (i)  the
discontinuance  of goodwill  amortization in 2002; (ii) the recording of special
items in 2001 which resulted in the recognition of certain gains and losses; and
(iii) a  significant  decrease in interest  expense in 2002.  These  benefits to
comparative  earnings were offset, in part, by a decrease in natural gas prices,
particularly  during the first quarter,  which reduced 2002 earnings  associated
with  gas  exploration  and  production  operations,  as well as the  impact  of
extremely warm weather during the first quarter which adversely affected natural
gas consumption by gas distribution customers.

In January 2002, we adopted Statement of Financial  Accounting Standard ("SFAS")
142  "Goodwill  and  Other  Intangible  Assets".  The key  requirements  of this
Statement  include  the  discontinuance  of  goodwill  amortization,  a  revised
framework   for  testing   goodwill   impairment   and  new   criteria  for  the
identification of intangible assets. Consolidated goodwill amortization for 2001
was $49.6 million, or $0.36 per share, and $19.7 million, or $0.15 per share for
2000.

During 2001, we recorded the effects of a number of events that impacted results
of operations for that year. These events are as follows: (1) we incurred losses
attributed to the former Roy Kay companies of $95.0 million after-tax,  or $0.69
per share,  primarily  reflecting  costs  related to the  discontinuance  of the
general  contracting  activities of these  companies,  costs to complete work on
certain loss construction projects, and operating losses incurred.  (See Note 10
to the  Consolidated  Financial  Statements,  "Roy  Kay  Operations"  and Note 7
"Contractual  Obligations,  Financial  Guarantees  and  Contingencies"  -  Legal
Matters,  for a further discussion of these issues); (2) our gas exploration and
production  subsidiaries  recorded a non-cash impairment charge to recognize the
effect of lower wellhead prices on their  valuation of proved gas reserves.  Our
share of this charge was $26.2 million after-tax,  or $0.19 per share. (See Note
1 to the Consolidated  Financial  Statements "Summary of Significant  Accounting
Policies",  Item F for further details); and (3) following a favorable appellate
court ruling, we reversed a previously recorded loss provision regarding certain
pending rate refund issues relating to the 1989 RICO class action  settlement of
$20.1 million after-tax,  or $0.15 per share. This adjustment has been reflected
as a $22.0  million  reduction  to  Operations  and  Maintenance  expense  and a
reduction of $11.5 million to Interest Charges on the Consolidated  Statement of
Income for the year ended  December 31, 2001.  (See Note 11 to the  Consolidated
Financial  Statements "Class Action Settlement" for a further discussion of this
issue.)

Interest expense decreased by $52.0 million ($33.8 million after-tax),  or $0.24
per share in 2002  compared  to 2001.  The  weighted  average  interest  rate on
outstanding  commercial  paper  for  2002 was  approximately  2.0%  compared  to
approximately 4.5% for last year. Further, KeySpan had a number of interest rate
swap  agreements  which  effectively  converted fixed rate debt to floating rate
debt. The use of these derivative  instruments reduced interest expense by $35.6
million in 2002. (See Note 8 to the Consolidated  Financial Statements "Hedging,
Derivative  Financial  Instruments,  and Fair Values" for a description of these
instruments.)  Interest  expense in 2001 also  reflects  the  reversal  of $11.5
million  in  accrued  interest  expense  resulting  from the RICO  class  action
settlement.


                                       31
<PAGE>


Net income from gas  exploration  and production  operations  decreased by $13.4
million,  or $0.11 per share,  in 2002 compared to 2001.  These  operations were
adversely  impacted  by  significantly   lower  realized  gas  prices  in  2002,
particularly in the first quarter.  As previously  mentioned,  these  operations
recorded  a non-cash  impairment  charge in 2001;  excluding  this  charge,  the
comparative decrease in earnings was $39.6 million, or $0.30 per share.

Income  tax  expense  generally  reflects  the level of  pre-tax  income for all
periods  reported.  Further,  during the year we finalized the  valuation  study
related to the assets  transferred to KeySpan  resulting  from the  KeySpan/Long
Island Lighting Company ("LILCO") business combination completed in May 1998. As
a result,  an  adjustment  to deferred  taxes of $177.7  million was recorded to
reflect a decrease in the tax basis of the assets acquired. Concurrent with this
adjustment,  KeySpan  reduced  current  income taxes payable by $183.2  million,
resulting in a $5.5 million income tax benefit. Income tax expense also reflects
additional  tax  benefits  of  approximately  $15  million  resulting  from  the
finalization of amended tax returns and the reversal of certain tax reserves.

Average  common  shares  outstanding  in 2002  increased  by 2% compared to 2001
reflecting  the  re-issuance  of shares  held in  treasury  pursuant to dividend
reinvestment and employee benefit plans.  This increase in average common shares
outstanding  reduced  earnings per share in 2002 by $0.06  compared to 2001.  In
January  2003, we received net proceeds of  approximately  $473 million from the
issuance of 13.9 million shares of common stock.  See the  discussion  under the
caption  "Capital  Expenditures  and Financing" for further  information on this
equity offering.

Earnings before interest and taxes ("EBIT")  increased by $116.4 million in 2002
compared  to last year.  Comparative  EBIT  results  were  impacted by the items
mentioned above,  namely; (i) the  discontinuation  of goodwill  amortization in
2002 of $49.6 million;  (ii) EBIT losses of $137.8  million  incurred by the Roy
Kay  companies  in 2001  compared to losses of $10.8  million  incurred in 2002;
(iii) the recording of a non-cash pre-tax  impairment charge of $42.0 million in
2001 to recognize the effect of lower wellhead prices; and (iv) the reversal, in
2001, of a previously  recorded loss provision relating to the RICO class action
settlement of $22.0  million.  Offsetting  these  benefits to  comparative  EBIT
results  was a  decrease  in EBIT in 2002 from gas  exploration  and  production
operations  resulting from a significant decline in average realized gas prices.
(See "Review of Operating  Segments"  and Note 2 to the  Consolidated  Financial
Statements  "Business  Segments"  for a detailed  discussion of EBIT results for
each of our lines of business.)

Earnings from continuing  operations less preferred stock dividends for the year
ended December 31, 2001 decreased by $46.9 million, or $0.40 per share, compared
to the same period in 2000. These  comparative  results were primarily driven by
the items recorded in 2001 that were previously discussed.

Further,  on  November 8, 2000 we  acquired  all of the common  stock of Eastern
Enterprises  ("Eastern") and EnergyNorth Inc. ("ENI") in a transaction accounted
for as a purchase. As a result,  comparisons in consolidated earnings,  revenues
and expenses between fiscal years 2001 and 2000 have been significantly affected
by the addition of these operations.  (See Note 1 to the Consolidated  Financial
Statements  "Summary  of  Significant  Accounting  Policies".)  As  part of this
transaction,  in 2000 we recorded a $65.2 million pre-tax charge associated with
early  retirement  and  severance   programs  that  were  implemented  upon  the
completion  of  the  acquisitions.  The  after-tax  effect  of  this  charge  on
consolidated results was $41.1 million, or $0.31 per share.


                                       32
<PAGE>


Interest expense  increased by $152.2 million,  or 75% in 2001 compared to 2000,
reflecting  higher levels of debt  outstanding,  primarily related to: (i) $1.65
billion of  long-term  debt and $308.6  million of  commercial  paper  issued to
finance the acquisition of Eastern and ENI; (ii) debt assumed in the Eastern and
ENI acquisition;  (iii) $625 million of notes issued during the year,  primarily
used to repay short-term debt; (iv) debt incurred by KeySpan Canada,  one of our
Canadian subsidiaries;  as well as (v) higher commercial paper borrowings during
the year to satisfy  seasonal  working capital needs. As mentioned,  we reversed
$11.5 million of previously recorded interest expense relating to the RICO class
action settlement during 2001, of which $9 million was recorded in 2000.

Income tax expense in 2001 generally  reflects the lower level of pre-tax income
compared to 2000. (See Note 3 to the Consolidated Financial Statements,  "Income
Taxes" for more  information.) The decrease in preferred stock dividends in 2001
compared to 2000  resulted  from the  redemption,  at maturity,  of 14.5 million
shares of preferred stock in the second quarter of 2000.

Average  common  shares  outstanding  in 2001  increased  by 3% compared to 2000
reflecting  the  re-issuance  of shares  held in  treasury  pursuant to dividend
reinvestment and employee benefit plans.  This increase in average common shares
outstanding reduced earnings per share in 2001 by $0.05 compared to 2000.

EBIT from continuing  operations in 2001,  after adjusting for the matters noted
above,  were  substantially   higher  than  such  earnings  for  2000.  Our  gas
distribution  operations  benefited  from the  addition  of the New  England gas
utilities  for the entire year in 2001  compared to only two months in 2000,  as
well as from an increase in net margins due to continued gas sales  growth,  and
cost saving synergies.  Further,  our gas exploration and production  activities
benefited  from the combined  effect of higher  realized  gas prices,  primarily
during the first quarter of 2001, and improved production volumes throughout the
year.  These benefits to EBIT from  continuing  operations  were almost entirely
offset by higher interest expense. In addition, during 2000 certain charges were
incurred by our  corporate  and  administrative  areas that were not incurred in
2001, which resulted in a significant increase to comparative earnings. (See the
discussion  under the heading "Review of Operating  Segments" for an analysis of
comparative EBIT for each of our operating segments.)

On January 24, 2002, we announced  that we had entered into an agreement to sell
Midland  Enterprises,  LLC  ("Midland"),  KeySpan's inland marine barge business
acquired in connection  with the Eastern  acquisition.  In  anticipation of this
divestiture, which was completed on July 2, 2002, Midland's operations have been
reported  as  discontinued  for all  periods.  (See  Note 9 to the  Consolidated
Financial  Statements  "Discontinued  Operations" for further  disclosure on the
sale of Midland.) In the fourth  quarter of 2001, an estimated  loss on the sale
of Midland,  as well as an estimate for Midland's  results of operations for the
first six months of 2002 was recorded.

As a result of a change in the tax structure of this transaction,  an additional
after-tax  loss of $19.7  million was recorded in 2002,  primarily  reflecting a
provision for certain city and state taxes.


                                       33
<PAGE>


Financial Outlook for 2003

Consistent with our prior earnings guidance,  and as reaffirmed in February 2003
following the  announcement  regarding the sale of a portion of our ownership in
The Houston Exploration Company ("Houston Exploration"), our gas exploration and
production subsidiary (as further discussed below),  KeySpan's earnings for 2003
are forecasted to be approximately $2.45 to $2.60 per share, after giving effect
to the sale of 13.9 million shares of common stock  previously  noted.  Earnings
from  continuing  core  operations  (defined for this purpose as all  continuing
operations  other than gas  exploration  and  production,  less preferred  stock
dividends) are forecasted to be  approximately  $2.15 to $2.20 per share,  while
earnings from gas  exploration  and  production  operations are forecasted to be
approximately  $0.30  to  $0.40  per  share.  The  earnings  forecast  may  vary
significantly during the year due to, among other things, changing energy market
and weather conditions.  It should be noted that, starting in 2003, KeySpan will
expense  stock  options  granted  to its  employees  in  order  to  reflect  all
prospective compensation costs in earnings.

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

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

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

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.   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  natural  gas
distribution  companies - Boston Gas Company,  Essex Gas  Company,  Colonial 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.


                                       34
<PAGE>


The table below highlights certain significant financial data and operating
statistics for the Gas Distribution segment for the periods indicated.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------
                                                                                  Year Ended December 31,
------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)                                                  2002               2001              2000
------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>                <C>               <C>
Revenues                                                               $ 3,163,761        $ 3,613,551       $ 2,555,785
Cost of gas                                                              1,569,325          2,017,782         1,303,515
Revenue taxes                                                               98,151            119,084           117,811
------------------------------------------------------------------------------------------------------------------------
Net Revenues                                                             1,496,285          1,476,685         1,134,459
------------------------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                                              608,266            593,341           456,028
   Early retirement and severance programs                                       -                  -            41,790
   Depreciation and amortization                                           237,186            253,523           143,335
   Operating taxes                                                         138,686            148,428           131,854
------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                                   984,138            995,292           773,007
------------------------------------------------------------------------------------------------------------------------
Operating Income                                                           512,147            481,393           361,452
Other Income and (Deductions), net                                          12,164             10,969             5,774
------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest Charges and Income Taxes                        $ 524,311          $ 492,362         $ 367,226
------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH)                                   284,281            283,081           221,689
Transportation - Electric
   Generation (MDTH)                                                        64,173             64,578            49,854
Other Sales (MDTH)                                                         209,002            188,037           126,372
Warmer (Colder) than Normal - New York                                        7.0%              10.0%             (2.1%)
Warmer (Colder) than Normal - New England                                     4.0%               4.6%             (3.3%)
------------------------------------------------------------------------------------------------------------------------
</TABLE>
A MDTH is 10,000 therms 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

Combined net gas  revenues  (revenues  less the cost of gas sold and  associated
revenue taxes) from our gas distribution  operations increased by $19.6 million,
or 1.3%.  Both the New York and New England  based gas  distribution  operations
were  adversely  impacted  by  the  significantly  warmer  than  normal  weather
experienced throughout the Northeastern United States during 2002,  particularly
during the first quarter.  Based on heating degree days,  weather for the twelve
months ended  December 31, 2002 was  approximately  4%-7% warmer than normal and
approximately  1%-3%  colder  than  last  year in the New York  and New  England
service territories.  However, weather during the heating season, January-March,
was approximately  16%-19% warmer than normal,  across our service  territories.
Our gas distribution  operations  historically earn  approximately 60% of yearly
EBIT during the January-March period.

During 2002, KEDNY and KEDLI, together, added approximately $40 million in gross
gas load additions. The increased gas sales were generated from oil-to-gas space
heating  conversions,  as well as from new  construction.  These load additions,
however,  were offset by declining  usage per customer due to the extremely warm
first  quarter  weather and the use of more  efficient  gas  heating  equipment.
Additionally,  the down-turn in the economy  throughout the Northeastern  United
States had an adverse  impact on gas  consumption  in 2002. As a result of these
factors,  net revenues  from firm gas  customers  (residential,  commercial  and
industrial  customers)  in our New  York  service  territory  decreased  by $1.5
million in 2002 compared to last year.  Included in net revenues are  regulatory
incentives  that  contributed  a  favorable  $6.7  million  to  comparative  net
revenues.


                                       35
<PAGE>

Net  revenues  from firm gas  customers  in the New  England  service  territory
increased by $20.5 million in 2002 compared to last year,  primarily as a result
of approximately  $24 million in gross gas load additions.  Also included in net
revenues are base rate adjustments totaling $10.0 million associated with Boston
Gas Company's Performance Based Rate Plan ("PBR"). The largest component of this
adjustment  reflects  the  beneficial  effect  of  a  favorable  ruling  of  the
Massachusetts    Supreme   Judicial   Court   relating   to   the   "accumulated
inefficiencies"  component of the  productivity  factor in the PBR.  This ruling
resulted  in a  benefit  to  comparative  net  margins  of  $6.3  million.  (See
"Regulation  and  Rate  Matters"  for a  further  discussion  of  this  matter.)
Offsetting,  to some extent,  these benefits to revenues are the adverse effects
of declining  usage per customer due to the extremely warm first quarter weather
and the use of more efficient gas heating equipment. Additionally, the down-turn
in the economy  throughout the Northeastern  United States had an adverse impact
on gas consumption in 2002.

KEDNY and KEDLI  each  operate  under  utility  tariffs  that  contain a weather
normalization  adjustment  that  significantly  offsets  variations  in firm net
revenues due to fluctuations in weather. These weather normalization adjustments
resulted in an increase to net gas revenues of $22.3  million in 2002,  but this
did not fully  mitigate the impact of the loss in revenues due to the  extremely
warm weather  experienced  during the first quarter.  The New  England-based gas
distribution  subsidiaries  do not have weather  normalization  adjustments.  To
lessen, to some extent, the effect of fluctuations in normal weather patterns on
KEDNE's results of operations and cash flows,  weather  derivatives are in place
for the 2002/2003 winter heating season. Since weather during the fourth quarter
of 2002 was 7% colder  than  normal in the New  England  service  territory,  we
recorded a $3.3  million  reduction  to  revenues  to reflect  the loss on these
derivative  transactions.  (See Note 8 to the Consolidated  Financial Statements
"Hedging,  Derivative  Financial  Instruments,  and  Fair  Values"  for  further
information).

Firm gas  distribution  rates  in 2002,  excluding  gas  cost  recoveries,  have
remained  substantially   unchanged  from  last  year  in  all  of  our  service
territories.

Total net gas revenues  increased by $342.2  million or 30% in 2001  compared to
2000.  The gas  distribution  operations  of KEDNE added $296.8  million to this
increase, while our New York based gas distribution operations accounted for the
remaining  $45.4  million  increase.  Net revenues  from our firm gas  customers
increased by $343.1 million in 2001 compared to 2000.  This increase was largely
driven by the addition of KEDNE's gas  distribution  operations  which accounted
for  $296.8  million  of the  increase.  Our New  York  based  gas  distribution
operations  added $9.2 million to firm net revenues in 2001 through the addition
of new gas customers and through our continuing  efforts to convert  residential
and commercial  customers from oil-to-gas for space heating purposes,  primarily
on Long Island.  In addition,  the comparative  increase in firm net revenues in
2001 was  favorably  affected by the recovery of  previously  deferred  property
taxes,  as well as  regulatory  incentives  that added  $13.3  million and $23.7
million,  respectively,  to the increase in firm net gas  revenues in 2001.  The
related  property tax expense is being  amortized  through  operating  taxes and
therefore does not benefit EBIT.


                                       36
<PAGE>


In our large-volume  heating and other interruptible  (non-firm) markets,  which
include large apartment houses, government buildings and schools, gas service is
provided under rates that are  established to compete with prices of alternative
fuel,  including  No. 2 and No. 6 grade  heating oil. Net margins  realized from
these  customers in 2002 are comparable to such margins  realized last year. Net
revenues in these markets in 2001 were slightly  lower than sales to this market
for 2000.  The majority of these margins  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 the New  England  service  territories.  We  estimate  that  on  Long  Island
approximately 35% of the residential and multi-family markets, and approximately
55% of the  commercial  market  currently  use  natural  gas for  space  heating
purposes.  Further,  we  estimate  that in the New England  service  territories
approximately 50% of the residential and multi-family markets, and approximately
45% of the  commercial  market  currently  use  natural  gas for  space  heating
purposes.  We will continue to seek growth in all of our market segments through
the expansion of the gas distribution  system, as well as through the conversion
of residential  homes from oil-to-gas for space heating purposes and the pursuit
of opportunities to grow multi-family, industrial and commercial markets.

Firm Sales, Transportation and Other Quantities

Total actual firm gas sales and transportation  quantities  remained  consistent
with last year. In the New York service territory, actual and weather normalized
firm gas sales and transportation quantities decreased slightly in 2002 compared
to  2001.  In  the  New  England  services  territories,   firm  gas  sales  and
transportation  quantities increased 4%, despite the warm first quarter weather,
due to load additions.

Firm gas sales and  transportation  quantities  increased  by 27%  during  2001,
compared to 2000. The gas distribution  operations of KEDNE,  accounted for 73.9
MDTH, or 100% of the increase. Firm gas sales and transportation quantities from
our New York based gas distribution  operations decreased by 7% compared to 2000
as a result of warmer than normal weather.  Weather was approximately 10% warmer
than normal in 2001 and approximately 11% warmer than the prior year.

Weather normalized sales quantities in 2001 in our New York service  territories
were flat compared to 2000 due primarily to the adverse effect on consumption of
extraordinarily high gas prices during the first quarter of 2001.

Net revenues are not affected by customers choosing to purchase their gas supply
from other sources,  since delivery  rates charged to  transportation  customers
generally are the same as the delivery  component of rates charged to full sales
service  customers.  Transportation  quantities  related to electric  generation
reflect the  transportation of gas to KeySpan's electric  generating  facilities
located on Long Island. Net revenues from these services are not material.


                                       37
<PAGE>


Other sales quantities include on-system  interruptible  quantities,  off-system
sales quantities  (sales made to customers  outside of our service  territories)
and related  transportation.  We have an agreement  with Coral  Resources,  L.P.
("Coral"),  a subsidiary of Shell Oil Company,  under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI. We also had a portfolio  management  contract with
El Paso Energy Marketing,  Inc. ("El Paso"), under which El Paso provided all of
the city gate supply  requirements at market prices and managed certain upstream
capacity, underground storage and term supply contracts for KEDNE. Our agreement
with El Paso expired on October 31, 2002 and our agreement with Coral expires on
March 31, 2003. We have negotiated a new agreement with  Entergy-Koch to replace
the expired El Paso  agreement.  The new agreement  with  Entergy-Koch  began on
November 1, 2002 and extends  through  March 31, 2003.  In  anticipation  of the
expiration  of the  existing  agreements,  a request  for  proposal  was sent to
various portfolio managers.  Upon evaluation of the bids, KeySpan will negotiate
agreements for all of its gas distribution subsidiaries.  It is anticipated that
such agreements will become effective April 1, 2003.

Purchased Gas for Resale

The decrease in gas costs in 2002  compared to 2001 of $448.5  million,  or 22%,
reflects a decrease of 26% in the price per  dekatherm of gas  purchased,  and a
1.0%  increase in the  quantity of gas  purchased.  The increase in gas costs in
2001 compared to 2000 of $714.3 million,  or 55% primarily reflects the addition
of KEDNE's  operations  for an entire year.  KEDNE's  operations  accounted  for
$666.1  million of the increase.  Fluctuations  in utility gas costs  associated
with firm gas  customers  have no impact on operating  results.  The current gas
rate  structure  of  each  of our  gas  distribution  utilities  includes  a gas
adjustment  clause,  pursuant  to which  variations  between  actual  gas  costs
incurred and gas costs  billed are  deferred  and refunded to or collected  from
customers in a subsequent period.

Operating Expenses

Operating  expenses  decreased by $11.2  million in 2002  compared to last year.
Comparative   operating   expenses   were   significantly    impacted   by   the
discontinuation of goodwill  amortization.  As previously mentioned,  in January
2002,  we adopted  Statement  of  Financial  Accounting  Standards  ("SFAS") 142
"Goodwill and Other Intangible Assets," which required,  among other things, the
discontinuation  of  goodwill  amortization.  Goodwill  amortization  in the gas
distribution  segment for the twelve  months  ended  December 31, 2001 was $35.6
million.  Excluding  the  effects  of  this  amortization,   operating  expenses
increased by $24.4 million, or 3%, in 2002 compared to last year.

The increase in operating  expense in 2002 is  attributable,  in part, to higher
pension and other  postretirement  benefits which increased by approximately $25
million,  net of amounts deferred and subject to regulatory  true-ups,  over the
level  incurred in 2001.  The cost of these  benefits  has risen  primarily as a
result of lower actual returns on plan assets,  as well as an increase in health
care costs. Further,  depreciation and amortization expense,  excluding the 2001
goodwill amortization, has also increased as a result of the continued expansion
of the gas distribution system.


                                       38
<PAGE>


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

Operating  expenses  increased by $222.3  million,  or 29%, in 2001  compared to
2000, due to the addition of the New England gas distribution operations,  which
added  $289.1  million to  operating  expenses  in 2001.  This  amount  includes
operations  and   maintenance   costs  of  $170.6  million,   depreciation   and
amortization  charges  of $91.0  million  and  general  taxes of $27.5  million.
Operating  expenses  related to our New York based gas  distribution  operations
decreased  in 2001  compared  to 2000,  as a result  of cost  savings  synergies
realized in 2001 and lower general and  administrative  costs being allocated to
our New York  operations  as a  result  of a  change  in 2001 of the  allocation
methodology for these costs pursuant to the Securities and Exchange Commission's
("SEC") requirements under PUHCA. Further, in 2000 we recorded a charge of $41.8
million associated with early retirement and severance programs implemented upon
the acquisition of Eastern and ENI.

Depreciation  and  amortization  expense in 2001 reflects  $35.6 million for the
amortization  of goodwill as  previously  noted,  as well as continued  property
additions,  and the amortization of certain costs that were previously  deferred
and were recovered through gas rates in 2001.

Other Matters

As previously  mentioned,  there remain significant growth  opportunities in our
Long Island and New England gas distribution service areas. The Northeast region
represents  a  significant  portion  of  the  country's  population  and  energy
consumption.  Gas sales  growth  and  customer  additions  are  critical  to our
earnings in the future. However, the beneficial effect of our growth initiatives
may not be fully  realized  in the  short-term  since we will  continue  to make
incremental   investments  in  our  gas  distribution  network  and  expand  our
promotional  campaigns to optimize the  long-term  growth  opportunities  in our
service territories.

To take advantage of the anticipated gas sales growth  opportunities  in our New
York  service  territory,  in 2000 we formed the  Islander  East  Pipeline,  LLC
("Islander East"), a limited liability company in which a KeySpan subsidiary and
a subsidiary of Duke Energy  Corporation each own a 50% equity interest.  During
2002,  Islander East received a certificate of public  convenience and necessity
from the Federal Energy  Regulatory  Commission  ("FERC") to construct,  own and
operate a natural gas pipeline facility  consisting of approximately 50 miles of
interstate  natural gas  pipeline  extending  from  Algonquin  Gas  Transmission
Company's facilities in Connecticut, across the Long Island Sound and connecting
with KEDLI's facilities on Long Island.  Islander East has obtained all required
permits in New York State for the  construction  of the facility.  However,  the
State of  Connecticut  has issued a  moratorium  on the  issuance of the permits
relating to the  construction of energy projects until June 2003.  Islander East
has  therefore  been unable to obtain the  necessary  permits  from the State of
Connecticut at this time.  Islander East has also appealed a denial by the State
of Connecticut of the coastal zone management permit to the U.S. Department of



                                       39
<PAGE>

Commerce and such appeal is currently  pending.  Assuming the timely  receipt of
approvals from the State of Connecticut,  the Islander East pipeline is expected
to begin operating by year-end 2004 and will transport  260,000 DTH daily to the
Long Island and New York City energy markets, enough fuel to heat 600,000 homes,
as well as allow us to  further  diversify  the  geographic  sources  of our gas
supply.  We are currently  evaluating  various options for the financing of this
pipeline.  (See the discussion  under "Capital  Expenditures  and Financing" for
more information on our financing plans for 2003.)

On December 12, 2002, we acquired Algonquin LNG, LP, the owner and operator of a
600,000  barrel  FERC-regulated   liquefied  natural  gas  ("LNG")  storage  and
receiving   facility  in  Providence,   Rhode  Island,   from  Duke  Energy  for
approximately  $28 million.  Algonquin LNG was renamed KeySpan LNG, L.P. and its
largest  customer is Boston Gas Company,  which  contracts for more than half of
the facility's storage capacity.

Electric Services

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

Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------
                                                                                    Year Ended December 31,
(In Thousands of Dollars)                                                  2002               2001              2000
------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>                <C>               <C>
Revenues                                                               $ 1,421,143        $ 1,421,179       $ 1,445,886
Purchased fuel                                                             262,072            281,398           315,139
------------------------------------------------------------------------------------------------------------------------
Net Revenues                                                             1,159,071          1,139,781         1,130,747
------------------------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                                              659,882            662,083           617,399
   Depreciation                                                             61,377             52,284            49,278
   Operating taxes                                                         150,495            155,693           158,886
------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                                   871,754            870,060           825,563
------------------------------------------------------------------------------------------------------------------------
Operating Income                                                           287,317            269,721           305,184
Other Income and (Deductions), net                                          22,346             13,812             5,639
------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest Charges and Income Taxes                        $ 309,663          $ 283,533         $ 310,823
------------------------------------------------------------------------------------------------------------------------
Electric sales (MWH)*                                                    5,020,741          4,932,836         4,865,344
Capacity(MW)*                                                                2,200              2,200             2,200
Cooling degree days                                                          1,474              1,381             1,075
------------------------------------------------------------------------------------------------------------------------
</TABLE>
*Reflects the operations of the Ravenswood facility only.


                                       40
<PAGE>


Net Revenues

Total  electric net revenues  increased by $19.3  million for the twelve  months
ended  December 31, 2002,  compared to the same period in 2001.  Net revenues in
2002  reflect net revenues of $17.3  million  from our new Glenwood  Landing and
Port  Jefferson  electric  "peaking"  facilities  located  on Long  Island.  The
Glenwood  facility  was  placed  in  service  on June 1,  2002,  while  the Port
Jefferson facility was placed in service on July 1, 2002. These facilities add a
combined 160 megawatts of generating  capacity to KeySpan's electric  generation
portfolio. The capacity of and energy produced by these facilities are dedicated
to LIPA under 25 year contracts.

Net revenues from the LIPA Agreements  increased by $47.2 million or 6% in 2002,
compared to last year.  Included in revenues for 2002,  are billings to LIPA for
certain third party costs that were significantly higher than such billings last
year.  These  revenues have minimal 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 2002 associated with the LIPA
Agreements were  comparable to such revenues last year. In addition,  in 2002 we
earned $16.0 million associated with non-cost  performance  incentives  provided
for under these  agreements,  compared to $16.2 million earned last year. (For a
description of the LIPA Agreements, see "LIPA Agreements".)

Net revenues from the Ravenswood  facility were $45.2 million,  or 13%, lower in
2002,  compared to 2001. Net revenues from capacity sales decreased 19% compared
to last year,  while margins  associated  with the sale of electric  energy were
basically  flat.  Comparative  energy sales  benefited from a 2% increase in the
megawatt hours sold as a result of the hot summer weather offset,  in part, by a
reduction in  "spark-spread"  (the  selling  price of  electricity  less cost of
fuel).  Measured in cooling degree days,  weather during the 2002 cooling season
was approximately 7% warmer than last year.

The decrease in net revenues from capacity  sales in 2002,  was due, in part, to
more competitive  pricing by the electric  generators that bid into the New York
Independent  System  Operator  ("NYISO")  energy market which  lowered  capacity
clearing prices by  approximately 8% compared to last year.  Further,  the NYISO
revised its methodology employed to determine the available supply of and demand
for installed capacity that also had an adverse impact on the capacity market by
reducing the capacity  required to be purchased by load serving entities such as
electric  utilities.  However, in September 2002, the NYISO recognized a flaw in
its revised methodology. Since this flaw resulted in insufficient capacity being
procured by the market,  it was identified as a reliability  concern.  The NYISO
corrected its methodology prior to the recent 2002/2003 winter auction to ensure
sufficient capacity is procured. Elimination of the flaw ensures compliance with
New York State Reliability  Rules. The Ravenswood  facility and the NYISO energy
market should  benefit from this  correction  since,  as a result,  load serving
entities  should  procure  sufficient  capacity  to  maintain   reliability  for
customers.

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.


                                       41
<PAGE>


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 discussion under Market and Credit Risk Management Activities for a further
discussion of these matters.)

Total  electric net revenues  increased  slightly in 2001 compared to 2000.  Net
revenues  from  the  Ravenswood  facility  decreased  by $12.6  million,  or 3%,
reflecting  lower realized  energy prices and lower ancillary  service  revenues
offset, in part, by effective hedging  strategies.  (Ancillary  services include
primarily  spinning  reserves  and  non-spinning  reserves  available to replace
energy  that is unable to be  delivered  due to the  unexpected  loss of a major
energy  source.)  Further,  capacity  and energy  sales  quantities,  as well as
realized  energy  prices were  adversely  impacted  by an increase in  available
capacity in New York City during 2001.

Revenues from the service agreements with LIPA increased by $22.7 million, or 3%
in 2001 compared to 2000. Included in revenues in 2001 were billings to LIPA for
certain  third  party  capital  costs that were  significantly  higher than such
billings  in  2000  primarily  due  to  the   construction   of  an  underground
transmission line to reinforce the electric system capacity on the South Fork of
Long Island.  As noted  previously,  these  revenues had a minimal impact on net
income. Excluding the third party billings, revenues in 2001 associated with the
LIPA  Agreements  were comparable to such revenues earned during the prior year.
In  addition,   in  2001  we  earned  $16.2  million  associated  with  non-cost
performance  incentives  provided for under these agreements,  compared to $15.4
million earned in 2000.

Operating Expenses

Operating  expenses  in 2002  were  consistent  with the  prior  year.  However,
included in comparative operating expenses is an increase in third party capital
costs that are fully recoverable from LIPA, as noted  previously.  Excluding the
increase in these costs,  operating expenses have decreased by approximately $48
million in 2002 compared to 2001. In addition to third party capital costs, LIPA
reimburses  KeySpan for costs directly  incurred by KeySpan in providing service
to  LIPA,  subject  to the  sharing  provisions  in the LIPA  Agreements.  These
reimbursements  are  based  on  predetermined   estimates  of  operating  costs.
Variations between certain actual operating costs incurred (i.e.  postretirement
costs and  property  taxes) and the  predetermined  estimates  are  deferred and
refunded to or  collected  from LIPA in  subsequent  periods.  As a result of an
adjustment related to this "true-up",  certain pension and other  postretirement
costs were  approximately  $23 million lower in 2002 compared to 2001.  Further,
during  2002,  we  settled  certain   outstanding   issues  with  LIPA  and  the
Consolidated  Edison  Company of New York,  Inc.  ("Consolidated  Edison")  that
resulted in a $20.3 million  decrease to  comparative  operating  expenses.  The
increase in depreciation  and  amortization  expense,  as indicated in the above
table,  primarily  reflects  depreciation  associated  with the two new electric
peaking facilities.

Operating expenses increased by $44.5 million,  or 5% in 2001, compared to 2000,
primarily as a result of the increase in third party costs  previously noted and
higher allocated charges for corporate and  administrative  costs due to changes
in our allocation methodology as prescribed under PUHCA.


                                       42
<PAGE>


Other Income and Deductions

The   increases  in  Other  Income  in  2002  and  2001  are  due  primarily  to
inter-company  interest  income  earned  by  subsidiaries  within  the  Electric
Services segment.  For the most part, the various subsidiaries of KeySpan do not
maintain separate cash balances. Rather, liquid assets are maintained in a money
pool, from and to which  subsidiaries  can either borrow or lend.  Inter-company
interest expense is charged to "borrowers",  while inter-company interest income
is  earned  by  "lenders".  In all  years  presented  in the  above  table,  the
subsidiaries within the Electric Services segment have been net "lenders" to the
money pool and, accordingly, have earned inter-company interest income. Interest
rates  associated with money pool borrowings are generally the same as KeySpan's
short-term  borrowing  rate. All  inter-company  interest  income and expense is
eliminated for consolidated financial reporting purposes.

Other Matters

As previously  mentioned,  both the Glenwood Landing and Port Jefferson electric
generating peaking facilities are fully  operational.  Short-term  financing was
used for the construction of these facilities,  but various financing options to
permanently  finance these  facilities are being  explored.  (See the discussion
under "Capital Expenditures and Financing" for more information on our financing
plans for 2003.) Further,  construction has begun on a new 250 MW combined cycle
generating  facility  at the  Ravenswood  facility  site.  The new  facility  is
expected to commence  operations in late 2003. The capacity and energy  produced
from this plant are anticipated to be sold into the NYISO energy markets. We are
also  progressing  through the siting process before the New York State Board on
Electric  Generation  Siting  and the  Environment  with a  proposal  to build a
similar 250 MW combined cycle electric  generating  facility on Long Island.  On
February 4, 2003, an Examiners' Recommended Decision was issued recommending the
granting of a certificate of  environmental  capability and public need for this
proposed facility.  In addition,  as part of our growth strategy, we continually
evaluate the possible  acquisition  of additional  generating  facilities in the
Northeast. However, we are unable to predict when or if any such facilities will
be  acquired  and the  effect  any such  acquired  facilities  will  have on our
financial condition, results of operations or cash flows.

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

In late 2002, LIPA announced, and we acknowledged,  that during 2001 and 2002 we
had made errors in reporting LIPA's electric system  requirements,  resulting in
an overestimation of LIPA's unbilled revenue. LIPA and KeySpan have continued to
review and audit the  reporting  of electric  system  requirements  for 2002 and
earlier  periods,  and have  determined  that,  in addition to the 2002 and 2001
overestimation,  unbilled  revenues  for  prior  periods  back to May 1998  were
slightly  underestimated.  Based upon the review,  the total  overestimation  in
unbilled revenues amounted to approximately $65 million.


                                       43
<PAGE>


The LIPA  revenue  estimation  error did not have an  impact on LIPA's  electric
rates charged to its customers nor to its cash balances.  We do not believe that
the LIPA revenue  estimation  error will have any material adverse impact on the
various agreements with LIPA or on our financial or operating performance.

Energy Services

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

The  table  below  highlights  selected  financial  information  for the  Energy
Services segment.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------
                                                                                     Year Ended December 31,
(In Thousands of Dollars)                                                   2002               2001              2000
------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>              <C>                 <C>
Revenues                                                                 $ 938,761        $ 1,100,167         $ 770,110
Less: cost of gas and fuel                                                 206,731            407,734           248,275
------------------------------------------------------------------------------------------------------------------------
Net Revenues                                                               732,030            692,433           521,835
Other operating expenses                                                   743,965            839,918           503,512
------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss)                                                    (11,935)          (147,485)           18,323
Other Income and (Deductions), net                                           1,558              3,993            (3,693)
------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) Before Interest Charges and Income Taxes                 $ (10,377)        $ (143,492)         $ 14,630
------------------------------------------------------------------------------------------------------------------------
</TABLE>

Comparative EBIT results for 2002 compared to 2001 were  significantly  impacted
by losses  incurred by one of our  subsidiaries.  In 2001, we  discontinued  the
general contracting activities related to the former Roy Kay companies, with the
exception of completion of work on then existing contracts,  based upon our view
that  the  general  contracting  business  is not a  core  competency  of  these
companies.  (See  Note 10 to the  Consolidated  Financial  Statements  "Roy  Kay
Operations"  for a more detailed  discussion.)  For the year-ended  December 31,
2001, we incurred an EBIT loss of $137.8 million  associated with the operations
of the former Roy Kay companies.  The Roy Kay EBIT results reflect costs related
to the discontinuation of the general contracting activities of these companies,
costs to complete  work on certain loss  construction  projects,  and  operating
losses.  We are  completing  the  contracts  entered  into by the former Roy Kay
companies  and, for the twelve months ended  December 31, 2002, we incurred EBIT
losses of $10.8  million  reflecting  increases in the estimates of and costs to
complete these contracts, and general and administrative expenses.

Excluding  the  results  of the former Roy Kay  companies,  the Energy  Services
segment  reflected an increase in EBIT of $6.1 million in 2002  compared to last
year. Revenues, excluding the Roy Kay companies,  decreased by $180.4 million in
2002, while the cost of fuel decreased by $201.0 million. These declines,  which
for the most part  offset  each other,  reflect  the  operations  of our gas and
electric  marketing  subsidiary.  In 2002,  this  subsidiary  began to focus its
marketing   efforts  on  higher  net  margin  customers  and  as  a  result  has
substantially decreased its customer base.


                                       44
<PAGE>


EBIT  results for the  Business  Solutions  group of  companies,  which  provide
mechanical  contracting,   plumbing,  engineering  and  consulting  services  to
commercial,  institutional,  and industrial customers, improved by $22.3 million
in 2002 compared to 2001. This increase reflects additional work being performed
on the backlog of projects  existing at year-end last year and the absence of $6
million  in losses  incurred  on four  major  projects  in 2001.  A  backlog  of
approximately $514 million presently exists, which is 20% below the December 31,
2001 level.

Offsetting the positive  contribution to EBIT by the Business Solutions group of
companies,  was a decrease  of $15.4  million  associated  with the Home  Energy
Services  group of companies.  These  companies  provide  residential  and small
commercial customers with service and maintenance of appliances,  as well as the
retail marketing of natural gas and electricity. Contributing to the decrease in
EBIT from Home Energy  Services  were the following  factors:  (i) the continued
adverse  impact  of the  down-turn  in the  economy;  (ii)  the  non-renewal  of
appliance service  contracts due to the warm first quarter weather;  (iii) costs
associated  with the  closing of a service  center;  and (iv) an increase in the
reserve  for bad debts.  Comparative  EBIT  results in 2002  benefited  from the
elimination of goodwill amortization, which for 2001 amounted to $8.2 million.

We continue to re-align  and/or combine a number of our service  centers in this
segment in order to reduce  operating  and  general  and  administrative  costs,
realize synergy savings and improve profitability.


Excluding  the  operations of the Roy Kay  companies,  EBIT for this segment was
$19.0  million  lower in 2001  compared to 2000,  reflecting  costs  incurred to
complete  certain loss  construction  contracts and higher  corporate  allocated
costs as a result of PUHCA requirements (See "Securities and Exchange Commission
Regulation" for further discussion.)

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  are engaged in gas and oil exploration and production,
and the development and acquisition of domestic  natural gas and oil properties.
At December 31, 2002, these investments  consisted of our 66% ownership interest
in  Houston  Exploration,  as  well  as  our  wholly-owned  subsidiary,  KeySpan
Exploration  and  Production,  LLC. In line with our strategy of  exploring  the
monetization  or  divesture  of certain  non-core  assets,  in  October  2002 we
monetized a portion of our assets in the joint  venture  drilling  program  with
Houston  Exploration  that was initiated in 1999.  We received  $26.5 million in
cash from Houston  Exploration  for 18.6 BCFe of  estimated  proved and probable
reserves.  The  proceeds  were used to pay down  short-term  debt;  there was no
earnings impact from this transaction. Further, in February 2003, we reduced our
ownership  interest  in Houston  Exploration  to  approximately  56% through the
repurchase, by Houston Exploration, of 3 million shares of common stock owned by
KeySpan.  The net proceeds of  approximately  $79 million received in connection
with this repurchase were used to pay down short-term debt.


                                       45
<PAGE>


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

Selected  financial data and operating  statistics for our gas  exploration  and
production  activities  is set  forth in the  following  table  for the  periods
indicated.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------
                                                                                       Year Ended December 31,
(In Thousands of Dollars)                                                   2002               2001              2000
------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>                <C>               <C>
Revenues                                                                 $ 357,451          $ 400,031         $ 274,209
Depletion and amortization expense                                         176,925            142,728            95,364
Full cost ceiling test write-down                                                -             41,989                 -
Other operating expenses                                                    70,267             55,653            44,435
------------------------------------------------------------------------------------------------------------------------
Operating Income                                                           110,259            159,661           134,410
Other Income and (Deductions), net*                                        (14,765)           (39,728)          (22,738)
------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest Charges and Income Taxes                         $ 95,494          $ 119,933         $ 111,672
------------------------------------------------------------------------------------------------------------------------
Natural gas and oil production (Mmcf)                                      106,044             93,968            80,415
Natural gas (per Mcf) realized                                            $   3.22          $    4.24         $    3.38
Natural gas (per Mcf) unhedged                                            $   3.06          $    4.09         $    3.97
------------------------------------------------------------------------------------------------------------------------
</TABLE>
*Operating  income above  represents  100% of our gas exploration and production
subsidiaries'  results for the periods  indicated.  Earnings before interest and
taxes, however, is adjusted to reflect minority interest.

Earnings Before Interest and Taxes

The decrease in EBIT of $24.4 million in 2002 compared to last year,  reflects a
24% reduction in average  realized gas prices  (average  wellhead price received
for production  including hedging gains and losses),  which lowered  comparative
revenues,  as well as an increase in operating  expenses  associated with higher
levels of production and a higher depletion rate. The adverse effect on revenues
resulting from the decline in average  realized gas prices was partially  offset
by an increase of 13% in production volumes.

The average realized gas price for 2002 was 105% of the average unhedged natural
gas price,  resulting in revenues that were $16.4  million  higher than revenues
that would have been achieved if derivative  financial  instruments had not been
in place during 2002. Houston  Exploration hedged  approximately 64% of its 2002
production,  principally  through  the  use of  costless  collars.  The  average
realized gas price for 2001 was 104% of the average  unhedged natural gas price,
resulting in revenues  that were $12.9  million  higher than revenues that would
have been achieved if  derivative  financial  instruments  had not been employed
during  2001.  These  derivative  instruments  are  designed to provide  Houston
Exploration with a more predictable cash flow, as well as to reduce its exposure
to fluctuations in natural gas prices. At December 31, 2002 Houston  Exploration



                                       46
<PAGE>


had derivative  positions in place to hedge  approximately  67% of its estimated
2003 production and  approximately  20% of its estimated 2004 production,  again
principally  through  the  use  of  costless  collars.   Depending  upon  market
conditions,  Houston Exploration may enter into additional  derivative positions
during 2003 to hedge a larger  portion of its estimated  2004  production.  (See
Note 8 to the Consolidated Financial Statements,  "Hedging, Derivative Financial
Instruments, and Fair Value" for further information.)

The  depreciation,  depletion  and  amortization  rate was $1.68 per Mcf for the
twelve  months ended  December 31, 2002,  compared to $1.49 per Mcf for the same
period in 2001,  reflecting  higher finding and development  costs together with
the addition of fewer new reserves.

In 2001, our gas  exploration  and production  subsidiaries  recorded a non-cash
impairment  charge of $42.0  million to recognize  the effect of lower  wellhead
prices on their  valuation  of proved gas  reserves.  Our share of this  charge,
which includes our joint venture ownership interest and minority  interest,  was
$26.2 million after-tax. Excluding this charge, the comparative decrease in EBIT
for  2002  compared  to  2001  would  have  been  greater.  (See  Note  1 to the
Consolidated  Financial Statements "Summary of Significant Accounting Policies",
Item F for more information on this charge.)

The increase in EBIT for 2001 compared to 2000  reflects a significant  increase
in gas exploration and production  revenues,  partially offset by an increase in
operating expenses associated with higher production volumes.  Revenues for 2001
benefited from the combined effect of a 17% increase in production volumes and a
25% increase in average realized gas prices.  As noted above,  2001 EBIT results
also reflect the  recording  of a non-cash  impairment  charge to recognize  the
effect of lower wellhead prices on the valuation of proved gas reserves.

As previously mentioned,  the average realized gas price in 2001 was 104% of the
average  unhedged  natural  gas price,  resulting  in  revenues  that were $12.9
million  higher  than  revenues  that would  have been  achieved  if  derivative
financial  instruments had not been employed  during 2001. The average  realized
gas price in 2000 was 85% of the average unhedged  natural gas price,  resulting
in revenues  that were $46.3  million  lower than  revenues that would have been
achieved if derivative financial instruments had not been in place during 2000.

Natural gas prices  continue to be volatile and the risk that we may be required
to  record an  impairment  charge  on our full  cost  pool  again in the  future
increases  when  natural  gas prices  are  depressed  or if we have  significant
downward revisions in our estimated proved reserves.

The table below indicates the net proved reserves of our gas exploration and
production subsidiaries for the periods indicated.
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------
                                                                Year Ended December 31,
                                             2002                       2001                        2000
---------------------------------------------------------------------------------------------------------------
                                      BCFe         %             BCFe          %             BCFe         %
---------------------------------------------------------------------------------------------------------------
<S>                                   <C>       <C>              <C>        <C>              <C>       <C>
Houston Exploration                    650        96.7%           608         94.0%           561        94.6%
KSE E&P                                 22         3.3%            39          6.0%            32         5.4%
---------------------------------------------------------------------------------------------------------------
Total                                  672       100.0%           647        100.0%           593       100.0%
---------------------------------------------------------------------------------------------------------------
</TABLE>


                                       47
<PAGE>


Selected financial data for our other energy-related investments is set forth in
the following table for the periods indicated.
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
                                                                            Year Ended December 31,
(In Thousands of Dollars)                                               2002         2001          2000
---------------------------------------------------------------------------------------------------------
<S>                                                                   <C>           <C>          <C>
Revenues                                                             $ 90,778      $ 98,287     $ 35,258
Operation and maintenance expense                                      57,161        71,411       31,551
Other operating expenses                                               17,623        20,883        9,988
---------------------------------------------------------------------------------------------------------
Operating Income                                                       15,994         5,993       (6,281)
Other Income and (Deductions), net                                     16,777        15,551       26,295
---------------------------------------------------------------------------------------------------------
Earnings Before Interest Charges and Income Taxes                    $ 32,771      $ 21,544     $ 20,014
---------------------------------------------------------------------------------------------------------
</TABLE>

The  increase in EBIT in 2002  compared to last year  primarily  reflects  lower
comparative  losses  associated  with  certain  technology-related  investments.
Further,  higher EBIT from our Northern Ireland  investments  were, for the most
part,  offset  by  lower  EBIT  realized  by  KeySpan  Canada.   KeySpan  Canada
experienced lower per unit sales prices, as well as lower quantities of sales of
natural  gas liquids in 2002,  as a result of  generally  lower oil prices.  The
pricing of natural gas liquids is directly related to oil prices.

Overall,  EBIT from these operations and investments in 2001 remained relatively
constant  compared to 2000.  EBIT growth from our investments in KeySpan Canada,
Northern Ireland and certain operations  purchased as part of our acquisition of
Eastern were offset, in part, by losses incurred from certain technology-related
investments.  Further,  in the fourth quarter of 2000, we acquired the remaining
50% interest in KeySpan Canada,  making us the sole owner. Results of operations
associated with KeySpan Canada have been fully consolidated since the additional
investment,  whereas prior to this  transaction,  KeySpan  Canada's results were
reported as equity income in Other Income and  (Deductions).

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

Allocated Costs

As previously  mentioned,  we are subject to the  jurisdiction  of the SEC under
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  regulations of PUHCA and the New York State Public Service  Commission
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.   Revised   allocation
methodologies,  approved  by the SEC,  have been in use since  2001 to  allocate
certain service company costs to affiliates.


                                       48
<PAGE>


These  non-operating  subsidiaries  incurred  certain  costs  in 2002  primarily
related to general  corporate  expenses  that were not  allocated to the various
operating  subsidiaries.  These expenses combined with inter-company  money pool
eliminations  (that were higher in 2002  compared  to 2001)  resulted in an EBIT
loss of  $27.6  million  in  2002.  In 2001,  these  non-operating  subsidiaries
realized EBIT of $34.0 million,  primarily  related to the $22.0 million benefit
associated with the favorable  appellate court decision regarding the RICO class
action settlement, previously mentioned.

During 2000,  certain costs were  incurred by our  corporate and  administrative
subsidiaries that were not allocated to other operating  segments,  and were not
incurred  in  2001.  These  unallocated  costs  had  a  significant   effect  on
comparative EBIT results between the two years and are as follows:  (i) a charge
of $10.0 million for a contribution to the KeySpan  Foundation (a not-for-profit
philanthropic  foundation  that makes  donations to local  charitable  community
organizations);  (ii) an impairment charge of $23.2 million  associated with our
equity  investment  in certain  technology-related  activities;  (iii)  branding
expenses  and other  costs  related to the  integration  of the  Eastern and ENI
companies of $24.6 million;  and (iv) early retirement and severance  charges of
$23.1 million.  Item (i) is reflected in "Other Income and  Deductions"  and all
other  items are  reflected  in  "Operations  and  Maintenance  expense"  in the
Consolidated Statement of Income for 2000. Further, during 2001 we: (i) recorded
the benefit associated with the favorable appellate court decision regarding the
RICO  class  action  settlement  at our  corporate  holding  company  level,  as
mentioned  previously,  which increased EBIT by $22.0 million;  and (ii) settled
certain   outstanding  issues  associated  with  LIPA  and  reallocated  certain
administrative  costs which combined added $15.8 million to EBIT. The net result
of the preceding items  contributed to the increase in EBIT of $137.0 million in
2001 associated with our non-operating subsidiaries.

Liquidity

Cash flow from operations decreased by $81.1 million, or 9%, in 2002 compared to
2001.  Operating cash flow from gas  exploration  and production  activities was
adversely impacted by significantly  lower realized gas prices in 2002. Further,
cash flow from  operations in 2002  reflects the funding of the minimum  pension
obligation related to our New England subsidiaries of $80 million. These adverse
effects on cash flow were  partially  offset by the  termination of two interest
rate swap agreements that resulted in a favorable operating cash flow benefit of
approximately  $23.4  million,  as well as lower income tax payments.  State and
federal tax payments  were lower in 2002,  compared to last year,  as KeySpan is
currently  in a refund  position  with regard to such taxes.  (See Note 8 to the
Consolidated Financial Statements,  "Hedging,  Derivative Financial Instruments,
and Fair Value" for an explanation of the interest rate hedges.)


                                       49
<PAGE>

Cash flow from operations for 2001 reflects strong results from gas distribution
and  electric  operations,   as  well  as  significant  contributions  from  gas
exploration  and  production  activities.  Further,  the decrease in natural gas
prices in the second  half of 2001 also had a positive  impact on cash flow from
operations.  As a result of the seasonal nature of gas distribution  operations,
we incur  significant  cash  expenditures  during  the  summer and early fall to
purchase and inject gas into our storage  facilities.  We recover these costs in
subsequent  periods as the gas is removed  from  storage  and  delivered  to our
customers,  primarily during the winter, for space heating purposes. Significant
cash flows are generated during the first two quarters of the subsequent  fiscal
year as we receive  payment from  customers for such heating  season use. Due to
the significant increase in gas prices during the summer and early fall of 2000,
gas cost  recoveries  for the first two  quarters of 2001 were greater than such
recoveries for the same period in 2000. Further, gas prices during the third and
fourth quarters of 2001 were lower than the prior year,  resulting in lower cash
expenditures  required to maintain  natural gas  inventory in storage.  Also, as
stated earlier, gas exploration and production  activities benefited from higher
gas  prices  during  the first two  quarters  of 2001  compared  to 2000.  These
enhancements  to cash flow were  partially  offset by an  increase  in  interest
payments due to higher levels of outstanding 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.

In 2002,  KeySpan renewed its existing 364-day revolving credit agreement with a
commercial  bank syndicate of 16 banks  totaling $1.3 billion,  a reduction from
the previous $1.4 billion  facility.  The credit facility is used to back up the
$1.3 billion commercial paper program.  The fees for the facility are subject to
a  ratings-based  grid,  with an annual fee of .075% on the total  amount of the
revolving  facility.  The credit  agreement  allows for KeySpan to borrow  using
several different types of loans;  specifically,  Eurodollar  loans,  Adjustable
Bank Rate ("ABR") loans, or competitively bid loans.  Eurodollar loans are based
on the Eurodollar rate plus a margin of 42.5 basis points for loans up to 33% of
the  facility,  and an  additional  12.5 basis  points for loans over 33% of the
total  facility.  ABR loans are based on the greater of the Prime Rate, the base
CD rate plus 1%, or the Federal Funds Effective Rate plus 0.5%.  Competitive bid
loans are based on bid results requested by KeySpan from the lenders.  We do not
anticipate borrowing against this facility; however, if the credit rating on our
commercial paper program were to be downgraded, it may be necessary to do so.

The  credit  facility  contains  certain   affirmative  and  negative  operating
covenants,  including  restrictions  on KeySpan's  ability to mortgage,  pledge,
encumber  or  otherwise  subject its  property  to any lien,  as well as certain
financial  covenants  that  require  us  to,  among  other  things,  maintain  a
consolidated  indebtedness to consolidated  capitalization ratio of no more than
66%, a decrease from the 68% ratio required under the previous credit facility.

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 December 31, 2002, consolidated  indebtedness,  as calculated under the terms



                                       50
<PAGE>


of the credit facility, was 64.6% of consolidated capitalization. This ratio was
reduced to 59.8% by the sale of 13.9  million  shares of common stock in January
2003  as  discussed  below.  Violation  of this  covenant  could  result  in the
termination  of the  credit  facility  and the  required  repayment  of  amounts
borrowed  thereunder,  as well as  possible  cross  defaults  under  other  debt
agreements.  (See discussion  under "Capital  Expenditures and Financing" for an
explanation of the MEDS Equity Units and the Ravenswood Master Lease.)

The  credit  facility  also  requires  that net cash  proceeds  from the sale of
significant  subsidiaries  be  applied  to  reduce  consolidated   indebtedness.
Further,  an acceleration of indebtedness of KeySpan or one of its  subsidiaries
for borrowed  money in excess of $25 million in the  aggregate,  if not annulled
within 30 days after written notice,  would create an event of default under the
Indenture  dated  November  1,  2000,   between  KeySpan   Corporation  and  the
JPMorganChase  Bank as Trustee.  At December 31, 2002, KeySpan was in compliance
with all covenants.

At December 31,  2002,  we had cash and  temporary  cash  investments  of $170.6
million.  During 2002,  we repaid  $132.8  million of  commercial  paper and, at
December 31, 2002,  $915.7  million of  commercial  paper was  outstanding  at a
weighted average annualized interest rate of 1.52%. We had the ability to borrow
up to an  additional  $384.3  million at December 31, 2002 under the  commercial
paper program.

During 2002,  Houston  Exploration  entered into a new revolving credit facility
with a commercial  banking  syndicate  that  replaced the previous  $250 million
revolving credit facility. The new facility provides Houston Exploration with an
initial  commitment of $300  million,  which can be increased at its option to a
maximum of $350 million with prior approval from the banking syndicate.  The new
credit facility is subject to borrowing base limitations,  initially set at $300
million  and  will be  re-determined  semi-annually.  Up to $25  million  of the
borrowing  base is  available  for the  issuance  of letters of credit.  The new
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 loans is payable at a
fixed rate equal to the sum of (a) a quoted reserve  adjusted  LIBOR rate,  plus
(b) a  variable  margin  between  1.25% and  2.00%,  depending  on the amount of
borrowings outstanding under the credit facility.

Financial  covenants  require Houston  Exploration  to, among other things,  (i)
maintain an interest  coverage ratio of at least 3.00 to 1.00 of earnings before
interest,  taxes and depreciation  ("EBITDA") to cash interest;  (ii) maintain a
total  debt to EBITDA  ratio of not more than 3.50 to 1.00;  and (iii)  hedge no
more than 70% of natural gas production  during any 12-month period. At December
31, 2002, Houston Exploration was in compliance with all financial covenants.

During 2002, Houston Exploration  borrowed $79 million under its credit facility
and repaid $71  million.  At  December  31,  2002,  $152  million of  borrowings
remained  outstanding at a weighted average  annualized  interest rate of 3.42%.


                                       51
<PAGE>

Also,   $0.4  million  was  committed  under   outstanding   letters  of  credit
obligations.  At December 31,  2002,  $147.6  million of borrowing  capacity was
available.  KeySpan Canada has two revolving  credit  facilities  with financial
institutions in Canada.  Repayments under these agreements totaled approximately
US $26.1  million  during 2002.  At December 31, 2002,  approximately  US $150.9
million was outstanding at a weighted average annualized interest rate of 3.23%.
KeySpan  Canada  currently has available  borrowings of  approximately  US $55.8
million.  These revolving  credit  agreements have been extended through January
2004. An event of default would exist under these credit  facilities if KeySpan,
as guarantor on the  facilities,  falls below  investment  grade rating or falls
below A3 or A- at a time when its consolidated  indebtedness,  as measured using
the same criteria employed under KeySpan's credit facility,  is greater than 66%
of consolidated capitalization or its cash flow to interest expense is less than
2.25 to  1.00.  At  December  31,  2002,  KeySpan  and  KeySpan  Canada  were in
compliance with all covenants.

On January 17, 2003,  KeySpan  sold 13.9  million  shares of common stock to the
open market and realized net proceeds of approximately $473 million.  All shares
were offered by KeySpan pursuant to the effective shelf  registration  statement
filed with the SEC. Net proceeds from the equity sale were used initially to pay
down  commercial  paper  and  reduced  our  debt  to  capitalization   ratio  by
approximately 480 basis points.  Consolidated indebtedness at December 31, 2002,
as calculated  under the terms of KeySpan's  credit  facility and,  adjusted for
this equity offering was 59.8% of consolidated  capitalization.  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.  The  anticipated  impact of additional
common  shares  outstanding  due to the equity  offering  offset by the expected
interest  savings from the  repayments of  commercial  paper is  anticipated  to
result in dilution of approximately 7% per share in 2003.

In connection  with the  KeySpan/LILCO  transaction,  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.  In an effort to
mitigate the dilutive effect of the equity issuance,  in February 2003,  KeySpan
notified LIPA of its intention to redeem  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.  It is
anticipated  that such  redemption  will take place  before the end of the first
quarter of 2003.  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.

The ratings on our long-term  debt have remained  unchanged  since  December 31,
2001.  The  following  table  represents  the ratings of our  long-term  debt at
December 31, 2002.  Currently,  these ratings are all on stable outlook with the
exception of Standard & Poor's rating on KeySpan which is on negative outlook.


                                       52
<PAGE>

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


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:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
                                                                        Year Ended December 31,
(In Thousands of Dollars)                                              2002               2001
-------------------------------------------------------------------------------------------------
<S>                                                               <C>                 <C>
Gas Distribution                                                  $   407,679        $   384,323
Electric Services                                                     371,885            211,816
Energy Investments                                                    324,486            437,976
Energy Services                                                        14,316             17,134
Corporate Unallocated                                                  15,511              8,510
-------------------------------------------------------------------------------------------------
                                                                  $ 1,133,877        $ 1,059,759
-------------------------------------------------------------------------------------------------
</TABLE>

Construction  expenditures related to the Gas Distribution segment are primarily
for the renewal and  replacement  of mains and services and for the expansion of
the gas distribution system. Construction expenditures for the Electric Services
segment  reflect costs to: (i) maintain our generating  facilities;  (ii) expand
the  Ravenswood  facility;  and (iii)  construct the new Long Island  generating
facilities as previously noted.  Construction expenditures related to the Energy
Investments  segment primarily reflect costs associated with gas exploration and
production   activities.   These  costs  are  related  to  the  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 December 31, 2002, total expenditures associated with the siting,  permitting
and construction of the Ravenswood expansion project, the siting, permitting and
procurement  of equipment for the Long Island 250MW  combined  cycle  generation
plant,  and the siting and permitting of the Islander East pipeline project were
$234.6 million.


                                       53
<PAGE>


Construction  expenditures for 2003 are estimated to be $1.1 billion,  including
estimated  expenditures  for the  construction  of the new  electric  generating
facilities.  The amount of future  construction  expenditures  is reviewed on an
ongoing  basis and can be  affected by timing,  scope and changes in  investment
opportunities.

Financing

At December 31, 2001,  KeySpan had  authorization  under PUHCA to issue up to $1
billion  of  securities  and  had an  existing  $1  billion  shelf  registration
statement on file with the SEC, with $500 million  available  for  issuance.  In
February 2002, we filed a new shelf  registration  statement for the issuance of
an additional $1.2 billion of securities, thereby giving us the ability to issue
up to $1.7 billion of debt, equity or various forms of preferred stock.

In May 2002, we issued $460 million of MEDS Equity Units at 8.75%  consisting of
a three-year forward purchase contract for our common stock and a six-year note.
The  purchase  contract  commits us three years from the date of issuance of the
MEDS Equity  Units to issue and the  investors to purchase a number of shares of
our common stock based on a formula tied to the market price of our common stock
at that time. The 8.75% coupon is composed of interest  payments on the six-year
note of 4.9% and premium  payments on the three-year  equity forward contract of
3.85%.   These   instruments  have  been  recorded  as  long-term  debt  on  our
Consolidated Balance Sheet, but rating agencies, as well as our credit facility,
consider  between  80% to 100% of the  instruments  as equity  for  purposes  of
calculating debt-to-total capitalization ratios. (See Note 6 to the Consolidated
Financial  Statements  "Long-Term  Debt" for further  details on the MEDS Equity
Units.)

The issuance of the MEDS equity  units  utilized  $920 million of our  financing
authority under both the shelf  registration and the PUHCA financing  authority.
Both the $460 million six-year note and the $460 million forward equity contract
are considered current issuances for these purposes. On December 6, 2002 the SEC
issued an order increasing the available  financing  authority under PUHCA to an
aggregate $780 million.  Following the recent common stock  offering  previously
mentioned  and shares  expected to be issued for  employee  benefit and dividend
reinvestment plans, we have approximately $40 million available for the issuance
of new securities under our current PUHCA  authorization.  However, the issuance
of  securities  in  connection  with  the  redemption  of  existing   securities
(including the promissory  notes  discussed  previously) is permitted  under our
PUHCA  authorization  notwithstanding  the  foregoing  limit.  We intend to seek
authorization to issue additional securities in the near term.

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

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


                                       54
<PAGE>


During 2003, we intend to issue  approximately $150 million of either taxable or
tax-exempt long-term debt securities,  the proceeds of which, it is anticipated,
will  be  used  to  re-pay  the  outstanding  commercial  paper  related  to the
construction of our two Long Island  peaking-power  plants. We also may issue an
additional  $200 to $300 million of  medium-term  or  long-term  debt in 2003 to
refinance  existing  indebtedness.  We will  continue  to  evaluate  our capital
structure  and  financing  strategy  for 2003 and  beyond.  We believe  that our
current sources of funding (i.e.,  internally  generated  funds, the issuance of
additional securities as noted above, and the availability of commercial paper),
together with the cash proceeds from the recent equity offering,  are sufficient
to meet our anticipated working capital needs for the foreseeable future.

Off-Balance Sheet Arrangements

Guarantees

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

Further,  at December 31, 2002  KeySpan has  guaranteed:  (i) $153.9  million of
surety bonds  associated  with certain  construction  projects  currently  being
performed  by  subsidiaries  within the Energy  Services  segment;  (ii) certain
supply contracts,  margin accounts and purchase orders for certain  subsidiaries
in the  aggregate  amount of $65.7  million;  (iii) the  obligations  of KeySpan
Ravenswood  LLC,  the  lessee  under the $425  million  Master  Lease  Agreement
associated  with the Ravenswood  facility;  and (iv) $64.4 million of subsidiary
letters of credit.  KeySpan has also  guaranteed $25 million  associated  with a
non-affiliated  company's line of credit.  These  guarantees are not recorded on
the  Consolidated  Balance Sheet. The guarantee of the KEDLI  medium-term  notes
expires in 2010, while the other guarantees have terms that do not extend beyond
2005;  however the Master Lease Agreement can be extended to 2009. At this 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 7 to the  Consolidated  Financial
Statements,  "Contractual  Obligations,  Financial Guarantees and Contingencies"
for a description  of the leasing  arrangement  associated  with the  Ravenswood
Master  Lease   Agreement  and  additional   information   regarding   KeySpan's
guarantees.)

Variable Interest Entity

We have an arrangement with a variable  interest entity through which we lease a
portion of the  Ravenswood  facility.  We acquired the Ravenswood  facility,  in
part, through the variable interest entity from 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, or three steam generating units, directly from Consolidated Edison and
leased it to a KeySpan subsidiary. The variable interest unaffiliated financing


                                       55
<PAGE>


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.

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 either purchase
the facility at the original  acquisition  cost of $425 million plus the present
value of the lease payments that would otherwise have been paid through June 20,
2009, or terminate  the Master Lease and dispose of the facility.  If the Master
Lease is  terminated,  KeySpan  has  guaranteed  an  amount  equal to 83% of the
original  acquisition  cost 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 adjustments,  or surrender the facility to
the lessor.  If we elect not to purchase the facility,  the lessor will sell the
property; we have guaranteed the lessor 84% of the original acquisition cost.

In January 2003, The Financial  Accounting  Standards Board (the "Board") issued
Interpretation No. 46 ("FIN 46"),  "Consolidation of Variable Interest Entities,
an Interpretation of ARB No. 51". This Interpretation would require us to, among
other things,  consolidate  this variable  interest entity for the first interim
period  ending after June 15,  2003,  so long as the current  variable  interest
structure remains intact.  This  Interpretation  will require us to classify the
Master Lease as debt on the  Consolidated  Balance Sheet at an amount  generally
equal to fair market  value.  As  previously  mentioned,  under the terms of our
credit   facility  the  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.  However,  such amount  cannot exceed the amount of
debt to be recorded for the variable  interest entity.  At this time, we believe
that the fair  market  value of the leased  assets is in excess of the  original
acquisition cost. The  Interpretation  contains certain other provisions that we
will be required to  implement  in 2003 and such  provisions  may impact  future
earnings.  (See Note 7 to the  Consolidated  Financial  Statements  "Contractual
Obligations,  Financial Guarantees and Contingencies" for additional information
on the Master Lease and Interpretation No. 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. KeySpan's outstanding short-term and long-term debt
issuances are explained in more detail in Note 6 to the  Consolidated  Financial
Statements "Long-Term Debt".  KeySpan's operating and capital leases, as well as
its  demand  charges  are  more  fully  detailed  in Note 7 to the  Consolidated
Financial  Statements   "Contractual   Obligations,   Financial  Guarantees  and
Contingencies".  The table  below  reflects  maturity  schedules  for  KeySpan's
contractual obligations at December 31, 2002:


                                       56
<PAGE>

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

 Contractual Obligations                   Total          1 - 3 Years     4 - 5 Years      After 5 Years
--------------------------------------------------------------------------------------------------------
<S>                                       <C>             <C>               <C>              <C>
 Long-term Debt                          $ 5,229,855     $ 1,337,999       $ 512,666        $ 3,379,190
 Capital Leases                               13,884           3,157           2,064              8,663
 Operating Leases                            604,782         244,306         159,508            200,968
 Demand Charges                              462,297         462,297               -                  -
--------------------------------------------------------------------------------------------------------
 Total Contractual
     Cash Obligations                    $ 6,310,818     $ 2,047,759       $ 674,238        $ 3,588,821
--------------------------------------------------------------------------------------------------------
 Commercial Paper                        $   915,697       Revolving
--------------------------------------------------------------------------------------------------------
</TABLE>

Discussion 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.  The  critical
accounting policies requiring such subjectivity are discussed below.

Percentage-of-Completion

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. Percentage-of-completion is measured principally
by comparing the  percentage of costs  incurred to date for each contract to the
estimated total costs for each contract at completion.  Provisions for estimated
losses on uncompleted  contracts are made in the period in which such losses are
determined.  Application of  percentage-of-completion  accounting results in the
recognition of costs and estimated earnings in excess of billings on uncompleted
contracts  (recorded  within the  Consolidated  Balance  Sheet) which arise when
revenues have been  recognized  but the amounts cannot be billed under the terms
of the contracts.  Such amounts are recoverable  from customers based on various
measures of performance, including achievement of certain milestones, completion
of specified units or completion of the contract.  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.  Application of  percentage-of-completion
accounting  requires that the impact of those  revised  estimates be reported in
the consolidated financial statements prospectively.


                                       57
<PAGE>


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  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.

Under SFAS 142,  goodwill is deemed  impaired if the fair value of the reporting
unit's  assets  is less  than  the  carrying  value of  those  assets  including
goodwill.  It was determined  that KeySpan's  financial  reporting  segments are
virtually the same as the reporting unit levels as defined in SFAS 142.

For those segments with goodwill, the following amounts were evaluated using the
standards set forth by SFAS 142 through December 31, 2002.

-------------------------------------------------------------------
(In Thousands of Dollars)
-------------------------------------------------------------------
Reporting Unit
   Gas Distribution                                    $ 1,592,510
   Energy Services                                         142,121
   Energy Investments and other                             55,120
-------------------------------------------------------------------
Total Goodwill                                         $ 1,789,751
-------------------------------------------------------------------


The majority of the goodwill  associated with the Gas Distribution unit resulted
from the  November  2000  acquisition  of  Eastern  and  ENI.  For  purposes  of
determining goodwill  impairment,  the fair value of the entire Gas Distribution
segment is evaluated  against the carrying value of the entire unit. Some of the
major  factors that were  considered  in  determining  the fair value of the Gas
Distribution  unit  included  assumptions  regarding  the  growth  in  revenues,
earnings before interest, taxes, depreciation and amortization, and the weighted
average cost of capital.

For the  initial  implementation  of SFAS  142,  the  fair  value of each of the
reporting  units  exceeded  the  carrying  value and no  impairment  charge  was
necessary.  The fair value for the reporting  units was  evaluated  based on the
present value of anticipated cash flows.

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.


                                       58
<PAGE>


In the case of the Gas  Distribution  and the Energy  Investments  segment,  the
above criteria have been met and no further  evaluation was required.  In regard
to the Energy Services segment,  criteria (b) was not met since the initial fair
value  valuation did not exceed the carrying  value by an amount deemed by us to
be substantial.  However, our annual test was performed in the fourth quarter of
2002 which verified that no impairment charge was deemed necessary. KeySpan will
continue to monitor the goodwill associated with this reporting unit.

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 a ten-year  period ending 2009.  Due to the length of these base rate
freezes,  the Colonial and Essex Gas Companies had previously  discontinued  the
application of SFAS 71.

SFAS 71 allows for the  deferral  of  expenses  and  income on the  consolidated
balance  sheet as  regulatory  assets and  liabilities  when it is probable that
those  expenses  and income  will be allowed  in the rate  setting  process in a
period  different from the period in which they would have been reflected in the
consolidated  statements of income of an  unregulated  company.  These  deferred
regulatory  assets  and  liabilities  are then  recognized  in the  consolidated
statement of income in the period in which the amounts are reflected in rates.

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. If we were unable to continue to apply the provisions
of SFAS 71 for any of our  rate  regulated  subsidiaries,  we  would  apply  the
provisions   of  SFAS  101   "Regulated   Enterprises   -  Accounting   for  the
Discontinuation  of  Application of FASB Statement No. 71." We estimate that the
write-off of all our net regulatory  assets at December 31, 2002 could result in
a charge to net  income of $230.1  million or $1.63 per  share,  which  would be
classified as an  extraordinary  item. 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.


                                       59
<PAGE>


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 anticipate  filing a base rate case and a performance  based rate
plan for Boston  Gas  Company in the  second  quarter of 2003.  Further,  we are
currently evaluating various options that may be available to us including,  but
not limited to, proposing new plans for KEDNY and KEDLI. The ultimate resolution
of any future rate plans could have a significant  impact on the  application of
SFAS 71 to these entities and, accordingly,  on our financial position,  results
of  operations  and cash flows.  However,  management  believes  that  currently
available  facts  support  the  continued  application  of SFAS 71 and  that all
regulatory  assets and  liabilities  are  recoverable or refundable  through the
regulatory environment.

Pension and Other Postretirement Benefits

As discussed in Note 4 of the Consolidated Financial Statements, "Postretirement
Benefits", KeySpan participates in both non-contributory defined benefit pension
plans, as well as other  post-retirement  benefit  ("OPEB") plans  (collectively
"postretirement plans").  KeySpan's reported costs of providing pension and OPEB
benefits  are  dependent  upon  numerous  factors  resulting  from  actual  plan
experience  and  assumptions  of  future  experience.  Pension  and  OPEB  costs
(collectively   "postretirement   costs")  are   impacted  by  actual   employee
demographics,  the level of  contributions  made to the plans,  earnings on plan
assets,  and health care cost trends.  Changes made to the  provisions  of these
plans may also impact current and future  postretirement  costs.  Postretirement
costs  may  also  be   significantly   affected  by  changes  in  key  actuarial
assumptions,  including,  anticipated  rates of  return on plan  assets  and the
discount  rates  used  in  determining  the  postretirement  costs  and  benefit
obligations.

The discount rate used for our postretirement  benefits at December 31, 2002 was
6.75%.  Our discount rate assumption is based upon the current  investment yield
associated with rating agency indices that have high quality long-term corporate
bonds.

For 2002, the assumed long-term return on our  postretirement  plans' assets was
8.5%. In selecting an assumed rate of return,  we consider past  performance and
economic  forecasts for the types of investments  held by the plans.  The actual
10-year  compound  rate  of  return,  net  of  all  expenses,  for  the  KeySpan
postretirement plans are greater than 8.5%. In addition, in eight of the last 10
years,  actual  returns have been greater than 8.5%. Our  postretirement  plans'
assets presently consist of approximately 65% equity, 33% fixed income/bonds and
2% cash. In an effort to maximize plan performance, actual asset allocation will
fluctuate from year to year depending on the then current economic  environment.
Based upon the historical performance of equity investments over time, our asset
allocation,  and our investment  strategy,  the assumed long-term rate of return
appears reasonable.

Our health care cost trend  assumptions  are developed  based on historical cost
data, the near-term  outlook and an assessment of likely long-term  trends.  The
salary growth assumptions reflect our long-term actual experience and future and
near-term outlook.


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<PAGE>


Actual results that differ from our assumptions are accumulated and amortized
over ten years.

Certain gas distribution  subsidiaries are subject to SFAS 71, and, as a result,
changes in  postretirement  expenses are deferred  for future  recovery  from or
refund to gas sales  customers.  Further,  changes  in  postretirement  expenses
associated with  subsidiaries that service the LIPA Agreements are also deferred
for future recovery from or refund to LIPA. As a result of these  deferrals,  we
estimate  that  the  actual  impact  of  postretirement   expense  to  KeySpan's
Consolidated   Statement  of  Income  is  approximately  50%  of  the  otherwise
actuarially determined expense.

The  year-end  December  31,  2002  assumed  discount  rate  used  to  determine
postretirement  obligations  was 6.75%. A 25 basis point increase or decrease in
the assumed  year-end  discount  rate would have had no impact on 2002  expense.
However,  a 25 basis point decrease in the assumed year-end  discount rate would
result in the recording of an additional minimum pension liability. Therefore, a
year-end  discount rate of 6.50% would have required an additional $76.4 million
debit to Other  Comprehensive  Income  ("OCI"),  net of tax and deferrals  noted
previously.  A year-end  discount rate of 7.00% would have reduced the charge to
OCI by a net $8.8 million.

At January 1, 2002, the assumed  discount rate used to determine  postretirement
obligations  was 7.0%.  A 25 basis  point  increase  or  decrease in the assumed
discount  rate at the  beginning of the year would have impacted 2002 expense by
approximately $4.2 million, net of tax and deferrals.

In 2002,  the expected rate of return on plan assets was 8.50%. A 25 basis point
increase  or  decrease in the return on plan  assets  would have  impacted  2002
expense by approximately $2.0 million, net of tax and deferrals.

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

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


                                       61
<PAGE>


evaluate  whether  the net book value of the full cost pool  exceeds the ceiling
limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization)  less deferred  taxes are greater than the  discounted  future net
revenues or ceiling limitation, a write-down or impairment of the full cost pool
is  required.  A  write-down  of the  carrying  value of the full cost pool is a
non-cash charge that reduces  earnings and impacts  stockholders'  equity in the
period of occurrence and typically results in lower depreciation,  depletion and
amortization  expense in future  periods.  Once  incurred,  a write-down  is not
reversible at a later date.

The ceiling test is calculated  using natural gas and oil prices in effect as of
the balance sheet date,  held  constant  over the life of the reserves.  Our gas
exploration and production  subsidiaries  use derivative  financial  instruments
that qualify for hedge accounting under SFAS 133 to hedge against the volatility
of natural  gas  prices.  In  accordance  with  current  SEC  guidelines,  these
derivatives are included in the estimated  future cash flows in the ceiling test
calculation.  In  calculating  the  ceiling  test  at  December  31,  2002,  our
subsidiaries  estimated that a full cost ceiling "cushion" existed,  whereby the
carrying  value of the full cost pool was less that the ceiling  limitation.  No
writedown is required when a cushion  exists.  Natural gas prices continue to be
volatile  and the risk that a write down to the full cost pool will be  required
increases  when  natural gas prices are  depressed  or if there are  significant
downward revisions in estimated proved reserves.

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

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.


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<PAGE>


All of our derivative instruments,  except for certain weather derivatives, meet
the SFAS 133  definition  of a  derivative.  For  those  derivative  instruments
designated as cash flow hedges, changes in the market value of substantially all
of our derivatives  are recorded in Other  Comprehensive  Income,  (in line with
effectiveness  measurements)  and are not recorded  through  earnings  until the
derivative  positions  are  settled.   Further,  none  of  KeySpan's  derivative
instruments  qualify  as  "energy  trading  contracts"  as  defined  by  current
accounting literature.

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

For collar  transactions  relating to natural gas sales  associated with our gas
exploration  and  production  subsidiaries,  we use standard  NYMEX quotes,  and
published  volatility with Black- Scholes valuations to calculate the fair value
of these instruments.

All fair value  measurements,  whether calculated using standard NYMEX quotes or
other  valuation  techniques,  are  subjective  and subject to  fluctuations  in
commodity prices,  interest rates and overall economic market conditions and, as
a result,  our fair  value  measurements  may not be precise  and can  fluctuate
significantly from period to period.

The table below  summarizes  the sources of fair value for cash-flow  derivative
instruments that qualify for hedge accounting treatment at December 31, 2002.
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)                                                       Fair Value of Contracts
---------------------------------------------------------------------------------------------------------------
                                                                     Maturity            Maturity      Total
Source of Fair Value                                                   2003                2004      Fair Value
---------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>               <C>            <C>
Prices actively quoted                                            $   (16,959)        $    (91)     $  (17,050)
Prices provided by external sources                                       124                -             124
Prices based on models and other valuation methods                    (10,743)          (3,675)        (14,418)
Local published indices                                                  (467)            (817)         (1,284)
---------------------------------------------------------------------------------------------------------------
                                                                  $   (28,045)        $ (4,583)     $  (32,628)
---------------------------------------------------------------------------------------------------------------
</TABLE>

During 2002,  we also had interest rate swap  agreements in which  approximately
$1.3 billion of fixed rate debt was effectively converted to floating rate debt.
The fair  values of these  derivative  instruments  were  provided  to us by our
counter-parties  and represent the present value of estimated future  cash-flows
based  on a  forward  interest  rate  curve  for  the  life  of  the  derivative
instrument.


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<PAGE>


Additionally,  we use  derivative  financial  instruments  to  reduce  cash flow
variability  associated  with the purchase price for a portion of future natural
gas  purchases  for our  regulated  gas  distribution  activities.  Since  these
derivative  instruments are employed to reduce 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. At December 31, 2002,
these  instruments  had a fair  value of $4.8  million  and were  valued  using,
primarily,  standard NYMEX quotes. These derivative  instruments will be settled
in 2003. Further, certain contracts for the physical purchase of natural gas for
our  regulated  firm gas sales  customers  can no longer be  exempted  as normal
purchases  from the  requirements  of SFAS 133.  At  December  31,  2002,  these
contracts had a fair value of $1.2 million.  The fair value for these  contracts
was determined using matrix-pricing models based on contracts with similar terms
and risks.

KeySpan also has a small number of derivative  financial  instruments  that meet
the SFAS 133 definition of a derivative but do not qualify for hedge  accounting
treatment.  Further,  these  instruments  do  not  qualify  as  "energy  trading
contracts" as defined by current accounting literature.  We use NYMEX futures to
economically  hedge the cash flow  variability  associated  with the purchase of
fuel for a portion of our fleet  vehicles.  KeySpan  Canada has a  portfolio  of
financially-settled   natural   gas   collars   and   natural  gas  liquid  swap
transactions.  Finally,  our retail gas and electric  marketing  subsidiary  has
bought options to economically hedge the cash flow variability associated with a
portion of expected  future natural gas purchases.  At December 31, 2002,  these
instruments,  all of which expire in 2003, had an unfavorable net mark-to-market
value of $0.4  million,  which was recorded to earnings.  We use standard  NYMEX
quotes,  local  published  commodity  indices,  and prices  provided by external
sources to value these instruments.

See  Note  8 to  the  Consolidated  Financial  Statements  "Hedging,  Derivative
Financial  Instruments  and Fair  Values" for a further  description  of all our
derivative instruments.

Dividends

We are currently  paying a dividend at an annual rate of $1.78 per common share.
Our dividend policy is reviewed  annually by the Board of Directors.  The amount
and timing of all dividend payments is subject to the discretion of the Board of
Directors  and will  depend upon  business  conditions,  results of  operations,
financial  conditions and other factors.  Based on currently  foreseeable market
conditions, we intend to maintain the dividend at the $1.78 level.

Pursuant to NYPSC  orders,  the ability of KEDNY and KEDLI to pay  dividends  to
KeySpan is conditioned upon maintenance of a utility capital structure with debt
not exceeding 55% and 58%,  respectively,  of total utility  capitalization.  In
addition,  the level of dividends  paid by both  utilities  may not be increased
from current  levels if a 40 basis point penalty is incurred  under the customer
service  performance  program.  At the end of  KEDNY's  and  KEDLI's  rate years
(September 30, 2002 and November 30, 2002,  respectively),  the ratio of debt to
total utility  capitalization was 42% and 52%,  respectively.  Additionally,  we
have met the requisite customer service performance standards. Our corporate and
financial  activities  and those of each of our  subsidiaries  (including  their
ability to pay  dividends to us) are also subject to regulation by the SEC. (For
additional  information,  see the discussion  under the heading  "Securities and
Exchange Commission Regulation").


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<PAGE>

Regulation and Rate Matters

Gas Distribution

By orders  dated  February 5, 1998 and April 14,  1998,  the NYPSC  approved the
KeySpan/LILCO  business combination and established gas rates for both KEDNY and
KEDLI.  Pursuant to the orders, $1 billion of efficiency savings,  excluding gas
costs, attributable to operating synergies that are expected to be realized over
the ten-year period following the combination,  were allocated to customers, net
of transaction costs.

Effective  May 29, 1998,  KEDNY's base rates to core  customers  were reduced by
$23.9 million  annually.  In addition,  KEDNY is subject to an earnings  sharing
provision pursuant to which it was required to credit core customers with 60% of
any utility  earnings up to 100 basis points above certain  threshold  return on
equity levels over the term of the rate plan (other than any earnings associated
with discrete incentives) and 50% of any utility earnings in excess of 100 basis
points above such threshold levels.  The threshold level for the rate year ended
September 30, 2002 was 13.25%.  KEDNY slightly  exceeded the threshold return on
equity for the rate year ended  September  30,  2002.  On  September  30,  2002,
KEDNY's rate agreement with the NYPSC expired. Under the terms of the agreement,
the then current gas distribution rates and all other provisions,  including the
earnings  sharing  provision (at the 13.25% threshold  level),  remain in effect
until changed by the NYPSC.  At this time, we are currently  evaluating  various
options that may be available to us regarding  KEDNY's rates,  including but not
limited to, proposing a new rate plan.

The 1998 orders also  required  KEDLI to reduce base rates to its  customers  by
$12.2 million  annually  effective  February 5, 1998 and by an  additional  $6.3
million annually effective May 29, 1998. KEDLI is subject to an earnings sharing
provision  pursuant to which it is required to credit to firm  customers  60% of
any utility  earnings in any rate year up to 100 basis  points above a return on
equity of 11.10% and 50% of any utility earnings in excess of a return on equity
of 12.10%.  KEDLI did not earn above its threshold return level in its rate year
ended  November 30, 2002. On November 30, 2000,  KEDLI's rate agreement with the
NYPSC expired. Under the terms of the agreement,  the gas distribution rates and
all other provisions,  including the earnings sharing provision,  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  KEDLI's  rate  plan,
including but not limited to, proposing a new rate plan.

We expect current gas distribution rates for KEDNY and KEDLI to remain in effect
through 2003.

Boston Gas Company,  Colonial Gas Company and Essex Gas Company  operations  are
subject to Massachusetts's  statutes applicable to gas utilities.  Rates for gas
sales and transportation  service,  distribution  safety practices,  issuance of
securities  and  affiliate  transactions  are  regulated by the DTE.



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<PAGE>


Boston Gas Company's gas rates for local distribution  service are governed by a
five-year  performance-based rate plan approved by the DTE in 1996 (the "Plan").
Under  the  Plan,  Boston  Gas  Company's  rates  for  local  distribution  were
recalculated  annually to reflect  inflation  for the  previous  12 months,  and
reduced by a  productivity  factor of 1%. The  productivity  factor has been the
subject of a remand proceeding at the DTE. With respect to this appeal, on March
7, 2002, the  Massachusetts  Supreme Judicial Court ruled in favor of Boston Gas
Company and reduced the productivity factor from 1.0% to .5%. Further,  the plan
contains a margin sharing mechanism,  whereby 25% of earnings in excess of a 15%
return on equity are passed back to customers.  Similarly, ratepayers absorb 25%
of any  shortfall  below a 7% return on equity.  The Plan expired on October 31,
2002.

On March 27, 2002, we filed notice, as required, with the DTE that we may file a
base rate case and a  performance  based rate plan for the Boston Gas Company to
replace the plan that  expired on October 31, 2002.  On May 21,  2002,  we filed
with the DTE a request to extend the existing performance based rate plan for an
additional  term of one  year.  This  request  was  denied  by the DTE in  early
September  2002.  As a  result,  we  anticipate  filing a base  rate  case and a
performance  based rate plan for the Boston Gas Company in the second quarter of
2003, to be effective in the fourth quarter of 2003.

In connection with the Eastern  acquisition of Colonial Gas Company in 1999, the
DTE  approved a merger and rate plan that  resulted in a ten year freeze of base
rates to Colonial Gas Company's firm customers.  The base rate freeze is subject
only to certain  exogenous  factors,  such as  changes  in tax laws,  accounting
changes,  or regulatory,  judicial,  or legislative  changes.  The Office of the
Attorney General  appealed the DTE's order to the Supreme Judicial Court,  which
appeal is still pending. Due to the length of the base rate freeze, Colonial Gas
Company  discontinued  its application of SFAS 71 "Accounting for the Effects of
Certain  Types of  Regulation".  Essex Gas Company is also under a ten-year base
rate freeze and has also  discontinued  its application of SFAS 71.

EnergyNorth Natural Gas, Inc.'s base rates continue as set by the NHPUC in 1993.

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  and ENI 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



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<PAGE>


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
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 December 31, 2002 our consolidated  common equity was 33% of
our consolidated  capitalization,  including  commercial  paper, and each of our
utility   subsidiaries  common  equity  was  at  least  35%  of  its  respective
capitalization.

Electric Services - Revenue Mechanisms

LIPA Agreements

KeySpan,  through certain of its  subsidiaries,  provides services to LIPA under
the following agreements:

Management Services Agreement ("MSA")

A KeySpan subsidiary manages the day-to-day operations,  maintenance and capital
improvements of the T&D system.  LIPA exercises  control over the performance of
the T&D system through  specific  standards for performance  and incentives.  In
exchange for providing the services, we earn a $10 million annual management fee
and are  operating  under a contract,  which  provides  certain  incentives  and
imposes certain penalties based upon  performance.  We have reached an agreement
with LIPA to extend the MSA for 31 months  through 2008, as discussed  under the
heading  "Generation  Purchase Right Agreement" below. Annual service incentives
or  penalties  exist  under  the MSA if  certain  targets  are  achieved  or not
achieved.  In addition,  we can earn  certain  incentives  for budget  underruns
associated with the day-to-day operations,  maintenance and capital improvements
of LIPA's T&D system.  These incentives provide for us to (i) retain 100% on the
first $5 million in annual budget  underruns,  and (ii) retain 50% of additional
annual  underruns  up to 15% of the total cost  budget,  thereafter  all savings
accrue to LIPA.  With  respect to cost  overruns,  we will  absorb the first $15
million of overruns,  with a sharing of overruns  above $15  million.  There are
certain limitations on the amount of cost sharing of overruns.  To date, we have
performed our obligations under the MSA within the agreed upon budget guidelines
and we  are  committed  to  providing  on-going  services  to  LIPA  within  the
established  cost  structure.  However,  no assurances can be given as to future
operating results under this agreement.


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<PAGE>

Power Supply Agreement ("PSA")

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.  Under the terms of the PSA,
rates will be reestablished for the contract year commencing  January 1, 2004 by
recalculating  the revenue  requirement  underlying  those rates.  We anticipate
submitting  to the  FERC a  rate  filing  reflecting  the  recalculated  revenue
requirement  in the Fall of 2003.  We are unable to predict  the outcome of that
proceeding  at this time.  Rates  charged to LIPA  include a fixed and  variable
component.  The variable  component is billed to LIPA on a monthly  basis and is
dependent on the number of megawatt hours dispatched.  LIPA has no obligation to
purchase  energy  conversion  services  from us and is able to  purchase  energy
conversion  services on a least-cost basis from all available sources consistent
with existing  interconnection  limitations of the T&D system.  The PSA provides
incentives and penalties that can total $4 million  annually for the maintenance
of the output  capability and the efficiency of the generating  facilities.  The
PSA runs for a term of fifteen  years,  with LIPA having the option to renew the
PSA for an additional fifteen year term.

Energy Management Agreement ("EMA")

The EMA provides for a KeySpan subsidiary to procure and manage fuel supplies on
behalf  of LIPA to fuel  the  generating  facilities  under  contract  to it and
perform  off-system  capacity and energy purchases on a least-cost basis to meet
LIPA's  needs.  In  exchange  for these  services  we earn an annual fee of $1.5
million.  In  addition,  we arrange  for  off-system  sales on behalf of LIPA of
excess output from the generating  facilities  and other power  supplies  either
owned or under  contract to LIPA.  LIPA is entitled to  two-thirds of the profit
from any off-system energy sales. In addition,  the EMA provides  incentives and
penalties  that can total $7 million  annually for  performance  related to fuel
purchases and  off-system  power  purchases.  The EMA covers a period of fifteen
years to 2013 for the  procurement  of fuel supplies and eight years to 2006 for
off-system management services.

Under  these  agreements,  we are  required  to obtain a letter of credit in the
aggregate  amount of $60  million  supporting  our  obligations  to provide  the
various  services  if our  long-term  debt is not  rated  in the "A"  range by a
nationally recognized rating agency.

Generation Purchase Right Agreement ("GPRA")

Under the GPRA,  LIPA had the right for a one-year  period  beginning on May 28,
2001, to acquire all of our Long Island based  generating  assets formerly owned
by LILCO at fair market value at the time of the exercise of such right.

By agreement  dated March 29, 2002, LIPA and KeySpan amended the GPRA to provide
for a new six month option period ending on May 28, 2005. The other terms of the
option reflected in the GPRA remained unchanged. In return for providing LIPA an
extension of the GPRA, KeySpan has been provided with a corresponding  extension
of 31 months for the MSA to the end of 2008.


                                       68
<PAGE>


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

KeySpan Glenwood and Port Jefferson Energy Centers

KeySpan  Glenwood Energy Center LLC and KeySpan Port Jefferson Energy Center LLC
have  entered into 25 year Power  Purchase  Agreements  with LIPA (the  "PPAs").
Under the terms of the PPAs, these subsidiaries sell capacity, energy conversion
services  and  ancillary  services to LIPA.  Both plants are designed to produce
79.9  megawatts.  Under  the  PPAs,  LIPA pays a  monthly  capacity  fee,  which
guarantees  full  recovery of each  plant's  construction  costs,  as well as an
appropriate rate of return on investment. The PPAs also obligate LIPA to pay for
each plant's  costs of operation  and  maintenance.  These costs are billed on a
monthly estimated basis and are subject to true-up for actual costs incurred.

Ravenswood Facility

We currently sell capacity,  energy and ancillary  services  associated with the
Ravenswood  facility  through a bidding process into the NYISO energy markets on
both a day ahead and a real time  basis.  We also have the ability to enter into
bilateral  transactions  to sell all or a portion of the energy  produced by the
Ravenswood  facility  to Load  Serving  Entities,  i.e.  entities  that  sell to
end-users or to brokers and marketers.

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  $192.9 million
and we have recorded a related  liability for such amount. We have also recorded
an additional $39.2 million liability,  representing the estimated environmental
cleanup costs related to a former coal tar processing  facility.  As of December
31,  2002,  we  have  expended  a  total  of  $70.5  million  on   environmental
investigation  and  remediation  activities.  (See  Note 7 to  the  Consolidated
Financial Statements,  "Contractual  Obligations,  Guarantees and Contingencies"
for a further explanation of these matters.)


                                       69
<PAGE>


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 Item 7A.  Quantitative  and
Qualitative  Disclosures  About  Market  Risk  and  Note 8 to  the  Consolidated
Financial Statements "Hedging, Derivative Financial Instruments and Fair Values"
for a further explanation of derivative financial instruments.)

Credit Risk: We are exposed to credit risk arising from the  potential  that our
counter-parties  fail to perform on their  contractual  obligations.  Our credit
exposures  are  created  primarily  through  the sale of gas and  transportation
services  to  residential,   commercial,  electric  generation,  and  industrial
customers and the provision of retail access  services to gas marketers,  by our
regulated gas  businesses;  the sale of commodities and services to LIPA and the
NYISO;  the sale of gas  power  and  services  to our  retail  customers  by our
unregulated  energy  service  businesses;  entering  into  financial  and energy
derivative contracts with energy marketing companies and financial institutions;
and the sale of gas, natural gas liquids,  oil and processing services to energy
marketing and oil 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 counter-parties may
impact  overall  exposure  to  credit  risk in that our  counter-parties  may be
similarly impacted by changes in economic,  regulatory or other  considerations.
We  actively  monitor the credit  profile of our  wholesale  counter-parties  in
derivative and other contractual arrangements,  and manage our level of exposure
accordingly.  Over the past year, the credit quality of certain energy companies
has declined. In instances where  counter-parties'  credit quality has declined,
we  limit  our  credit  exposure  by  restricting  new  transactions   with  the
counter-party, requiring additional collateral or credit support and negotiating
the early termination of certain agreements.


                                       70
<PAGE>


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.  Set forth below is a description of
these exposures.

The Gas Industry

Long Island and New York

The NYPSC continues to conduct collaborative  proceedings on ways to develop the
competitive  energy market in New York. On July 13, 2001, the presiding officers
in the case issued their recommended decision ("RD"). The RD recommends that the
NYPSC adopt an end state vision that includes  removing the  utilities  from the
provision of the energy (gas and  electric)  commodity.  The RD also  recommends
that  utilities  exit the  commodity  function  only  where  there is a workably
competitive  market.  The RD  states  that the  only  market  that is  currently
workably competitive is the commodity market for non-residential  large- use gas
customers. Parties filed briefs on and opposing exceptions to the RD.

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

As a result of circumstances in 2001, including the California energy crisis and
the  bankruptcy  of  Enron  Corp.,  state  regulators  around  the  country  are
reassessing the pace of movement toward  deregulation.  We are unable to predict
the  outcome  or pace of this  trend or its  ultimate  effect on our  results of
operation, financial condition or cash flows.

On December 20, 2002, New York State Governor  George Pataki signed into law the
"Energy  Consumer  Protection  Act of  2002"  ("Act").  The Act  defines  energy
services  companies that provide gas or electric  commodity service to customers
as utilities subject to the Home Energy Fair Practices Act provisions  ("HEFPA")
of the New York Public  Service  Law.  Under the Act,  in certain  circumstances
utilities  such as KEDNY and KEDLI  will be  required  to  suspend  distribution
service to customers  whose  commodity  service has been terminated by an energy
services company. Generally, those energy services companies are required under


                                       71
<PAGE>


the Act to provide these customers with the same consumer protections prescribed
under  HEFPA  as  are  prescribed  for  full  service  sales  customers  of  gas
distribution  companies.  Those consumer protections include a series of notices
warning of potential service termination,  offering deferred payment agreements,
and special  protections  for  elderly,  blind and disabled  customers.  The Act
contemplates  that the NYPSC will promulgate  regulations  implementing the Act,
but such regulations have not yet been promulgated. The Act becomes effective on
June 18, 2003. We cannot predict the impact of the Act on KeySpan's regulated or
unregulated operations at this time.

New England

In July 1997,  the DTE  directed  Massachusetts  gas  distribution  companies to
undertake a  collaborative  process with other  stakeholders  to develop  common
principles under which  comprehensive  gas service  unbundling might proceed.  A
settlement  agreement  by the  local  distribution  companies  ("LDCs")  and the
marketer group regarding model terms and conditions for unbundled transportation
service was  approved by the DTE in November  1998.  In February  1999,  the DTE
issued its order on how  unbundling of natural gas service will  proceed.  For a
five year transition period, the DTE determined that LDC contractual commitments
to  upstream  capacity  will be  assigned  on a  mandatory,  pro-rata  basis  to
marketers  selling gas supply to the LDC's  customers.  The  approved  mandatory
assignment method eliminates the possibility that the costs of upstream capacity
purchased  by the LDCs to serve firm  customers  will be  absorbed by the LDC or
other customers through the transition  period. The DTE also found that, through
the  transition  period,  LDCs will retain primary  responsibility  for upstream
capacity  planning and procurement to assure that adequate capacity is available
to support customer requirements and growth. The DTE approved the LDCs Terms and
Conditions of Distribution  Service that conform to the settled upon model terms
and conditions. Since November 1, 2000, all Massachusetts gas customers have the
option to purchase  their gas supplies  from third party  sources other than the
LDCs.  Further,  the  New  Hampshire  Public  Utility  Commission  required  gas
utilities to offer  transportation  services to all commercial  and  residential
customers starting November 1, 2001.

We believe that the actions  described  above strike a balance  among  competing
stakeholder  interests in order to most  effectively make available the benefits
of the unbundled gas supply market to all customers.

Electric Industry

The Ravenswood Facility and our New York City Operations

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


                                       72
<PAGE>


Regional Transmission Organizations and Standard Market Design

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

New York Independent System Operator Matters

On May 31, 2002,  FERC approved the NYISO's  mitigation  plan ("the Plan").  The
Plan retains existing mitigation measures such as $1,000/MWhr energy price caps,
non-spinning  reserve bid caps, in-City capacity and energy mitigation measures,
the day ahead Automated  Mitigation  Procedure ("AMP"),  and the NYISO's general
mitigation authority.  In addition,  the Plan implements a new in-City real time
automated mitigation  procedure.  Although prices for various energy products in
the NYISO  markets have  softened,  it is not known to what extent each of these
proceedings  and revised rules may impact the  Ravenswood  facility's  financial
condition, results of operations or cash flows.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The market risks discussed below relate to our derivative financial instruments.
We have derivative financial instruments and derivative commodity contracts that
are  exposed  to  potential  losses due to adverse  changes in  interest  rates,
commodity  prices and weather.  Interest  rate risk  generally is related to our
outstanding debt and financing  activities.  The majority of our commodity price
risk and  volumetric  risk due to  weather  relate  to our  Ravenswood  merchant
electric  operations,   exploration  and  production   operations  and  our  gas
distribution  operations.  We use derivative  contracts to manage price risk and
volumetric risk exposure from these activities.


                                       73
<PAGE>


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

Houston Exploration has utilized collars,  as well as  over-the-counter  ("OTC")
swaps to hedge the cash flow  variability  associated with forecasted sales of a
portion  of its  natural  gas  production.  As of  December  31,  2002,  Houston
Exploration has hedged  approximately 67% and 20% of its estimated 2003 and 2004
production, respectively. Further, Houston Exploration may enter into additional
derivative  positions for 2003 and 2004.  Houston  Exploration used standard New
York Mercantile  Exchange  ("NYMEX") futures prices and published  volatility in
its Black-Scholes calculation to value its outstanding derivatives.  The maximum
length  of time  over  which  Houston  Exploration  has  hedged  such  cash flow
variability is through December 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 $34.9  million,  or
$22.7 million after-tax.

With respect to price exposure associated with fuel purchases for the Ravenswood
facility,  KeySpan  employs  standard  NYMEX  natural gas futures  contracts and
over-the-counter  financially  settled natural gas basis swaps to hedge the cash
flow  variability of a portion of forecasted  purchases of natural gas.  KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow  variability of a portion of forecasted  purchases of fuel oil that will be
consumed at the  Ravenswood  facility.  The maximum length of time over which we
have hedged cash flow variability  associated with: (i) forecasted  purchases of
natural gas is through December 2003; and (ii) forecasted  purchases of fuel oil
is through April 2004. We used  standard  NYMEX futures  prices to value the gas
futures contracts and industry published oil indices for number 6 grade fuel oil
to value the oil swap contracts.  The estimated  amount of gains associated with
all such derivative  instruments that are reported in Other Comprehensive Income
and that are  expected to be  reclassified  into  earnings  over the next twelve
months is $4.5 million, or $2.9 million after-tax.

Our retail gas and electric marketing subsidiary,  our domestic gas distribution
operations and KeySpan Canada  employed NYMEX natural gas futures  contracts and
natural gas swaps to lock-in a price for expected  future natural gas purchases.
As applicable,  we used standard  NYMEX futures prices and relevant  natural gas
indices to value the  outstanding  contracts.  The  maximum  length of time over
which we have hedged such cash flow  variability  is through  December 2003. The
estimated amount of gains  associated with such derivative  instruments that are
reported in Other Comprehensive  Income and that are expected to be reclassified
into  earnings  over the next twelve  months is $4.9  million,  or $3.2  million
after-tax.


                                       74
<PAGE>


We have also engaged in the use of  cash-settled  swap  instruments to hedge the
cash flow variability  associated with (i) a portion of forecasted peak electric
energy sales from the Ravenswood  facility and (ii) forecasted sales of Unforced
Capacity  ("UCAP") to the NYISO.  The maximum  length of time over which we have
hedged cash flow variability is through March 2004. We used  NYISO-location zone
published  indices as well as  published  NYISO  bidding  prices to value  these
outstanding  derivatives.  The estimated  amount of losses  associated with such
derivative  instruments that are reported in Other Comprehensive Income and that
are expected to be  reclassified  into  earnings  over the next twelve months is
$1.1 million, or $0.7 million after-tax.

KeySpan  Canada also has  employed  electricity  swap  contracts  to lock-in the
purchase price of electricity needed to operate its gas processing plants. These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $1.5 million, or $1.0 million after-tax.

The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at December
31, 2002.
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------
          Type of Contract                Year of      Volumes                                        Current    Fair Value
                                          Maturity      mmcf      Floor $    Ceiling $  Fixed Price $  Price $      ($000)
----------------------------------------------------------------------------------------------------------------------------
                 Gas
<S>                                        <C>        <C>         <C>         <C>      <C>           <C>           <C>
Collars                                     2003       54,300      3.48        4.92             -     4.43-4.99     (14,681)
                                            2004       18,300      3.50        4.75             -     4.03-4.81      (3,767)

Swaps/Futures - Short Natural Gas           2003       14,751         -           -     2.91-3.52     3.87-4.99     (20,694)

Swaps/Futures - Long Natural Gas            2003       10,580         -           -     3.10-5.38     4.43-5.02       7,428
----------------------------------------------------------------------------------------------------------------------------
                                                       97,931                                                       (31,714)
----------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                                                            Fair
    Type of Contract           Year of      Volumes                          Current        Value
                               Maturity      Barrel    Fixed Price $          Price $      ($000)
---------------------------------------------------------------------------------------------------
           Oil
<S>                             <C>      <C>           <C>                  <C>            <C>
Swaps - Short Fuel Oil           2003      90,000             28.50          28.14-31.00      (145)

Swaps - Long Fuel Oil            2003     320,815       20.05-27.20          23.72-33.81     2,633
                                 2004       5,548       20.50-23.70          22.66-23.19         6
---------------------------------------------------------------------------------------------------
                                          416,363                                            2,494
---------------------------------------------------------------------------------------------------
</TABLE>


                                       75
<PAGE>


<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                                                                         Fair
  Type of Contract      Year of                         Fixed Margin/                    Value
                        Maturity   Capacity    MWh         Price $     Current Price $   ($000)
----------------------------------------------------------------------------------------------
    Electricity
<S>                       <C>       <C>      <C>       <C>               <C>          <C>
Swaps - Energy             2003               119,680   12.70-57.80       14.15-48.09  (1,889)
                           2004                68,800         14.00       22.25-22.34    (823)

Swaps - Capacity           2003      1,000                     7.75         7.00-9.41    (696)
----------------------------------------------------------------------------------------------
                                     1,000    188,480                                  (3,408)
----------------------------------------------------------------------------------------------
</TABLE>


------------------------------------------------------------------------------
Change in Fair Value of Derivative Instruments                          2002
                                                                       ($000)
------------------------------------------------------------------------------
Fair value of contracts at January 1,                               $  55,097
(Gain) on contracts realized                                          (26,204)
Fair value of new contracts when entered into during period                 -
(Decrease) in fair value of all open contracts                        (61,521)
------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31,                 $ (32,628)
------------------------------------------------------------------------------


NYMEX  futures  are also used to  economically  hedge the cash flow  variability
associated  with the  purchase  of fuel for a  portion  of our  fleet  vehicles.
Further,  KeySpan  Canada has a  portfolio  of  financially-settled  natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i)  synthetically  fix the price that is paid or received by
KeySpan  Canada for  certain  physical  transactions  involving  natural gas and
natural gas liquids and (ii) transfer the price exposure of such  instruments to
other  trading  partners.  In addition,  our retail gas and  electric  marketing
subsidiary has bought options to  economically  hedge the cash flow  variability
associated  with a portion of  expected  future  natural  gas  purchases.  These
derivative financial  instruments do not qualify for hedge accounting under SFAS
133. At December  31,  2002,  these  instruments  had a net fair market value of
($0.4) million,  that was recorded on the Consolidated  Balance Sheet.  Based on
the non-hedge  designation of these instruments,  the loss was recognized in the
Consolidated Statement of Income.

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


                                       76
<PAGE>


The following  table sets forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at December 31, 2002.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
                                                                                                  Fair
     Type of Contract            Year of       Volumes                                           Value
                                 Maturity       mmcf         Fixed Price $     Current Price $   ($000)
-------------------------------------------------------------------------------------------------------
<S>                               <C>          <C>            <C>                 <C>           <C>
Options                            2003         5,560          3.90-4.50                4.27     3,250

Swaps                              2003         2,080          3.85-4.50           4.79-4.95     1,586
-------------------------------------------------------------------------------------------------------
                                                7,640                                            4,836
-------------------------------------------------------------------------------------------------------
</TABLE>

Physically-Settled  Commodity  Derivative  Instruments:  On  April  1,  2002  we
implemented  Derivative  Implementation  Group ("DIG") Issue C15 and C16 of SFAS
133, "Accounting for Derivative Instruments and Hedging Activities",  as amended
and interpreted,  incorporating SFAS 137 and SFAS 138 and certain implementation
issues  (collectively  "SFAS 133"). Issue C15 establishes new criteria that must
be satisfied in order for option-type and forward contracts in electricity to be
exempted as normal purchases and sales, while Issue C16 relates to the exemption
(as normal  purchases  and normal  sales) of  contracts  that  combine a forward
contract and a purchased  option  contract.  Based upon a review of our physical
commodity  contracts,  we  determined  that certain  contracts  for the physical
purchase of natural gas can no longer be exempted as normal  purchases  from the
requirements  of SFAS  133.  At  December  31,  2002,  the  fair  value of these
contracts  was $1.2  million.  Since  these  contracts  are for the  purchase of
natural gas sold to regulated firm gas sales customers, the accounting for these
contracts is subject to SFAS 71. Therefore, changes in the market value of these
contracts  have been recorded as a Regulatory  Asset or Regulatory  Liability on
the Consolidated Balance Sheet.

Interest Rate Derivative Instruments:  During most of 2002, we had interest rate
swap agreements in which  approximately $1.3 billion of fixed rate debt had been
synthetically modified to floating rate debt. Under the terms of the agreements,
we  received  the fixed  coupon  rate  associated  with these bonds and paid the
counter-parties  a variable  interest rate that was reset on a quarterly  basis.
These swaps were  designated as fair-value  hedges and qualified for "short-cut"
hedge  accounting  treatment  under SFAS 133.  Through the  utilization of these
agreements, we reduced recorded interest expense by $35.6 million for the twelve
months ended  December 31, 2002.  In early  November  2002,  we  terminated  two
interest rate swap agreements with an aggregate  notional amount of $1.0 billion
and received $80.9 million from our swap counter-parties, of which $23.4 million
represented  accrued  swap  interest.  The  difference  between the  termination
settlement amount and the amount of accrued swap interest,  $57.4 million,  will
be amortized to earnings (as an adjustment to interest expense) on a level yield
basis over the remaining lives of the originally  hedged debt  obligations.  The
remaining swap, which had a notional amount of $270.0 million, and a fair market
value of $15.6  million at December 31,  2002,  was  terminated  on February 25,
2003.  We received  $18.4 million from our swap  counter-parties,  of which $8.1
million represents accrued swap interest. The difference between the termination
settlement  amount and the amount of accrued  interest,  $10.3 million,  will be
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 6 to
the Consolidated  Financial  Statements  "Long-Term Debt", we intend to redeem a
portion of these promissory notes before the end of the first quarter of 2003.


                                       77
<PAGE>


Additionally,  we also have an interest rate swap agreement that hedges the cash
flow  variability  associated  with  the  forecasted  issuance  of a  series  of
commercial paper offerings. The maximum length of time over which we have hedged
such cash flow  variability is through March 2003. The estimated  amount of loss
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 $0.6 million, or $0.4 million after-tax.

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  substanial  portion  of the  effect  of
fluctuations  from normal weather on our financial  position and cash flows,  we
sold  heating  degree-day  call options and  purchased  heating  degree-day  put
options for the November 2002 - March 2003 winter  season.  With respect to sold
call  options,  KeySpan is  required  to make a payment of $40,000  per  heating
degree day to its  counter-parties  when actual weather  experienced  during the
November 2002 - March 2003 time frame is above 4,470 heating degree days,  which
equates  to  approximately  1% colder  than  normal  weather.  With  respect  to
purchased  put options,  KeySpan  will receive a $20,000 per heating  degree day
payment  from its  counter-parties  when actual  weather is below 4,150  heating
degree days, or is  approximately  7% warmer than normal.  Based on the terms of
such contracts,  as discussed in Note 1 to the Consolidated Financial Statements
"Summary of Significant  Accounting  Policies",  we account for such instruments
pursuant to the requirements of EITF 99-2, "Accounting for Weather Derivatives."
In this  regard,  we account for such  instruments  using the  "intrinsic  value
method"  as set forth in such  guidance.  During  the  fourth  quarter  of 2002,
weather  was 7% colder  than  normal  and,  as a result,  $3.3  million has been
recorded as a reduction to revenues.

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

Foreign Currency Fluctuations

We  follow  the  principles  of SFAS  52,  "Foreign  Currency  Translation"  for
recording our investments in foreign affiliates. Due to our continued activities
in Canada and Northern  Ireland,  our investment in foreign  affiliates has been
growing.  At  December  31,  2002,  the  net  assets  of  these  affiliates  was
approximately  $374 million and at December 31, 2002, the accumulated  after-tax
foreign currency  translation included in Other Comprehensive Income was a debit
of $2.2 million.  (See Note 1 to the Consolidated  Financial Statements "Summary
of Significant Accounting Policies.")



                                       78

<PAGE>


Item 8. Financial Statements and Supplementary Data

                           CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
                                                                                        Year Ended December 31,
(In Thousands of Dollars)                                                             2002                   2001
--------------------------------------------------------------------------------------------------------------------
ASSETS
<S>                                                                                <C>                   <C>
Current Assets
      Cash and temporary cash investments                                        $    170,617          $    159,252
      Accounts receivable                                                           1,122,022             1,009,166
      Unbilled revenue                                                                473,060               335,732
      Allowance for uncollectible accounts                                            (63,029)              (72,299)
      Gas in storage, at average cost                                                 273,036               334,999
      Material and supplies, at average cost                                          113,519               105,693
      Other                                                                           127,224               125,944
                                                                        ---------------------- ---------------------
                                                                                    2,216,449             1,998,487
                                                                        ---------------------- ---------------------

Assets Held for Disposal                                                                    -               191,055
Investments and Other                                                                 259,188               223,249

Property
      Gas                                                                           6,124,281             5,704,857
      Electric                                                                      1,974,352             1,629,768
      Other                                                                           394,374               400,643
      Accumulated depreciation                                                     (2,740,516)           (2,533,466)
      Gas exploration and production, at cost                                       2,438,998             2,200,851
      Accumulated depletion                                                          (973,889)             (796,722)
                                                                        ---------------------- ---------------------
                                                                                    7,217,600             6,605,931
                                                                        ---------------------- ---------------------

Deferred Charges
      Regulatory assets                                                               438,516               458,191
      Goodwill, net of amortization                                                 1,789,751             1,782,826
      Other                                                                           692,802               529,867
                                                                        ---------------------- ---------------------
                                                                                    2,921,069             2,770,884
                                                                        ---------------------- ---------------------

Total Assets                                                                     $ 12,614,306          $ 11,789,606
                                                                        ====================== =====================
</TABLE>
        See accompanying Notes to the Consolidated Financial Statements.



                                      79
<PAGE>


                           CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>

--------------------------------------------------------------------------------------------------------------------
                                                                                         Year Ended December 31,
(In Thousands of Dollars)                                                              2002                  2001
--------------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
<S>                                                                               <C>                   <C>
Current Liabilities
      Current Redemption of long-term debt                                       $     11,413          $        993
      Accounts payable and other liabilities                                        1,061,649             1,091,430
      Commercial paper                                                                915,697             1,048,450
      Dividends payable                                                                64,714                63,442
      Taxes accrued                                                                    51,276                50,281
      Customer deposits                                                                38,387                36,151
      Interest accrued                                                                 77,092                93,962
                                                                        ---------------------- ---------------------
                                                                                    2,220,228             2,384,709
                                                                        ---------------------- ---------------------

Deferred Credits and Other Liabilities
      Regulatory liabilities                                                           84,479                39,442
      Deferred income tax                                                             877,013               598,072
      Postretirement benefits and other reserves                                      759,731               694,680
      Other                                                                           189,912               207,992
                                                                        ---------------------- ---------------------
                                                                                    1,911,135             1,540,186
                                                                        ---------------------- ---------------------

Commitments and Contingencies (See Note 7)                                                  -                     -

Capitalization
      Common stock                                                                  3,005,354             2,995,797
      Retained earnings                                                               522,835               452,206
      Other comprehensive income                                                     (108,423)                4,483
      Treasury stock                                                                 (475,174)             (561,884)
                                                                        ---------------------- ---------------------
           Total common shareholders' equity                                        2,944,592             2,890,602
      Preferred stock                                                                  83,849                84,077
      Long-term debt                                                                5,224,081             4,697,649
                                                                        ---------------------- ---------------------
Total Capitalization                                                                8,252,522             7,672,328
                                                                        ---------------------- ---------------------

Minority Interest in Subsidiary Companies                                             230,421               192,383
                                                                        ---------------------- ---------------------
Total Liabilities and Capitalization                                             $ 12,614,306          $ 11,789,606
                                                                        ====================== =====================
</TABLE>

        See accompanying Notes to the Consolidated Financial Statements.


                                       80
<PAGE>

                        CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                                                                               Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts)                                   2002              2001              2000
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>               <C>               <C>
Revenues
     Gas Distribution                                                             $ 3,163,761       $ 3,613,551       $ 2,555,785
     Electric Services                                                              1,421,043         1,421,079         1,444,711
     Energy Services                                                                  938,761         1,100,167           770,110
     Gas Exploration and Production                                                   357,451           400,031           274,209
     Energy Investments                                                                89,650            98,287            35,887
                                                                            ------------------------------------------------------
Total Revenues                                                                      5,970,666         6,633,115         5,080,702
Operating Expenses
     Purchased gas for resale                                                       1,653,273         2,171,113         1,408,680
     Fuel and purchased power                                                         385,059           538,532           460,841
     Operations and maintenance                                                     2,101,897         2,114,759         1,659,736
     Early retirement and severance charges                                                 -                 -            65,175
     Depreciation, depletion and amortization                                         514,613           559,138           330,922
     Operating taxes                                                                  410,651           448,924           421,936
                                                                            ------------------------------------------------------
Total Operating Expenses                                                            5,065,493         5,832,466         4,347,290
                                                                            ------------------------------------------------------
Operating Income                                                                      905,173           800,649           733,412
                                                                            ------------------------------------------------------
Other Income and (Deductions)
     Interest charges                                                                (301,504)         (353,470)         (201,314)
     Income from equity investments                                                    14,096            13,129            20,010
     Minority interest                                                                (24,918)          (40,847)          (26,342)
     Interest income                                                                    1,572             8,326            12,327
     Other                                                                             28,325            26,598           (18,081)
                                                                            ------------------------------------------------------
Total Other Income and (Deductions)                                                  (282,429)         (346,264)         (213,400)
                                                                            ------------------------------------------------------
Earnings Before Income Taxes                                                          622,744           454,385           520,012
Income Taxes
     Current                                                                          (48,487)          101,738           170,809
     Deferred                                                                         273,881           108,955            46,453
                                                                            ------------------------------------------------------
Total Income Taxes                                                                    225,394           210,693           217,262
                                                                            ------------------------------------------------------

Earnings from Continuing Operations                                                   397,350           243,692           302,750
                                                                            ------------------------------------------------------
Discontinued Operations
    Income (loss) from operations, net of tax                                          (3,356)           10,918            (1,943)
    Loss on disposal, net of tax                                                      (16,306)          (30,356)                -
                                                                            ------------------------------------------------------
Loss from Discontinued Operations                                                     (19,662)          (19,438)           (1,943)
                                                                            ------------------------------------------------------

Net Income                                                                            377,688           224,254           300,807
Preferred stock dividend requirements                                                   5,753             5,904            18,113
                                                                            ------------------------------------------------------
Earnings for Common Stock                                                         $   371,935       $   218,350       $   282,694
                                                                            ======================================================
Basic Earnings Per Share:
  Continuing Operations, less preferred stock dividends                           $      2.77       $      1.72       $      2.12
  Discontinued Operations                                                               (0.14)            (0.14)            (0.02)
                                                                            ------------------------------------------------------
Basic Earnings Per Share                                                          $      2.63       $      1.58       $      2.10
                                                                            ======================================================
Diluted Earnings Per Share
  Continuing Operations, less preferred stock dividends                           $      2.75       $      1.70       $      2.11
  Discontinued Operations                                                               (0.14)            (0.14)            (0.02)
                                                                            ------------------------------------------------------
Diluted Earnings Per Share                                                        $      2.61       $      1.56       $      2.09
                                                                            ======================================================
Average Common Shares Outstanding (000)                                               141,263           138,214           134,357
Average Common Shares Outstanding - Diluted (000)                                     142,300           139,221           135,165
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

        See accompanying Notes to the Consolidated Financial Statements.


                                       81
<PAGE>

                      CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
                                                                                             Year Ended December 31,
(In Thousands of Dollars)                                                            2002              2001              2000
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>               <C>              <C>
Operating Activities
Earnings from continuing operations                                               $ 397,350         $ 243,692        $ 302,750
Adjustments to reconcile net income to net
      cash provided by (used in) operating activities
    Depreciation, depletion and amortization                                        514,613           559,138          330,922
    Early retirement and severance accruals                                               -                 -           65,175
    Deferred income tax  (See Note 3)                                                90,724           108,955           46,453
    Income from equity investments                                                  (14,096)          (13,129)         (20,010)
    Dividends from equity investments                                                 3,905             7,570           21,507
    Gain from class action settlement                                                     -           (33,510)               -
    Provision for losses on contracting business                                          -            63,682                -
Changes in assets and liabilities
    Accounts receivable                                                            (259,454)          401,976         (800,033)
    Materials and supplies, fuel oil and gas in storage                              54,174           (43,856)         (36,952)
    Accounts payable and other liabilities                                          (19,745)         (425,196)         452,076
    Interest accrued                                                                 22,661            24,560           32,659
    Other                                                                            18,945            (3,701)          44,179
                                                                          -----------------------------------------------------
Net Cash Provided by Operating Activities                                           809,077           890,181          438,726
                                                                          -----------------------------------------------------
Investing Activities
    Construction expenditures                                                    (1,133,877)       (1,059,759)        (633,035)
    Other investments                                                               (27,579)                -         (292,222)
    Acquisition of Eastern Enterprise and EnergyNorth, Inc.                               -                 -       (1,762,007)
    Investment held for disposal                                                          -                 -         (184,036)
    Proceeds from sale of assets                                                    175,110            18,458                -
    Other                                                                                 -                (6)            (510)
                                                                          -----------------------------------------------------
Net Cash (Used in) Investing Activities                                            (986,346)       (1,041,307)      (2,871,810)
                                                                          -----------------------------------------------------
Financing Activities
    Treasury stock issued                                                            86,710            88,786           72,289
    Issuance of long-term debt                                                      549,280           812,116        2,166,955
    Payment of long-term debt                                                      (124,991)         (183,410)         (68,365)
    Issuance (payment) of commercial paper                                         (132,753)         (251,787)         935,372
    Payment of preferred stock                                                            -                 -         (363,000)
    Preferred stock dividends paid                                                   (5,753)           (5,904)         (20,261)
    Common stock dividends paid                                                    (250,903)         (245,598)        (239,740)
    Termination of interest rate swaps                                               57,415                 -          (59,490)
    Other                                                                             9,629            12,846          (35,949)
                                                                          -----------------------------------------------------
Net Cash Provided by Financing Activities                                           188,634           227,049        2,387,811
                                                                          -----------------------------------------------------
Net (Decrease) or Increase in Cash and Cash Equivalents                           $  11,365         $  75,923        $ (45,273)
Cash and Cash Equivalents at Beginning of Period                                    159,252            83,329          128,602
                                                                          -----------------------------------------------------
Cash and Cash Equivalents at End of Period                                        $ 170,617         $ 159,252        $  83,329
                                                                          =====================================================
Interest Paid                                                                     $ 318,374         $ 328,910        $ 165,020
Income Tax Paid                                                                   $  98,344         $ 128,558        $ 187,219
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>

        See accompanying Notes to the Consolidated Financial Statements.


                                       82
<PAGE>

                   CONSOLIDATED STATEMENT OF RETAINED EARNINGS
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
                                                                             Year Ended December 31,
(In Thousands of Dollars)                                           2002               2001                2000
-------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>                 <C>                 <C>
Balance at Beginning of Period                                   $ 452,206           $ 480,639           $ 456,882
Net Income for Period                                              377,688             224,254             300,807
-------------------------------------------------------------------------------------------------------------------
                                                                   829,894             704,893             757,689
Deductions:
Cash dividends declared on common stock                            252,175             246,783             239,740
Cash dividends declared on preferred stock                           5,753               5,904              20,298
MEDS Equity Units                                                   49,131                   -                   -
Other, primarily write-off of
    capital stock expense                                                -                   -              17,012
-------------------------------------------------------------------------------------------------------------------
Balance at End of Period                                         $ 522,835           $ 452,206           $ 480,639
-------------------------------------------------------------------------------------------------------------------
</TABLE>



                 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
                                                                                               Year Ended December 31,
(In Thousands of Dollars)                                                               2002             2001            2000
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>              <C>             <C>
Net Income                                                                            $ 377,688        $ 224,254       $ 300,807
--------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
 Net gains on derivative instruments                                                    (17,033)         (27,690)              -
 Reclassification adjustment for other gains reclassified to net income                       -           (3,242)              -
 Foreign currency translation adjustments                                                 9,759           (9,627)         (7,320)
 Unrealized gains (losses) on marketable securities                                     (10,019)          (5,464)          3,131
 Accrued unfunded pension obligation                                                    (55,768)         (13,262)              -
 Unrealized (losses) gains on derivative financial instruments                          (39,845)          62,943               -
--------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax                                          (112,906)           3,658          (4,189)
--------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income                                                                  $ 264,782        $ 227,912       $ 296,618
--------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
 Net gains on derivative instruments                                                     (9,172)       $ (14,910)      $       -
 Reclassification adjustment for other gains reclassified to net income                       -           (1,746)              -
 Foreign currency translation adjustments                                                 5,255           (5,184)         (3,941)
 Unrealized gains (losses) on marketable securities                                      (5,395)          (2,942)          1,686
 Accrued unfunded pension obligation                                                    (30,029)          (7,140)              -
 Unrealized  (losses) gains on derivative financial instruments                         (21,454)          33,892               -
--------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense                                                           $ (60,795)       $   1,970       $  (2,255)
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>

        See accompanying Notes to the Consolidated Financial Statements.


                                       83
<PAGE>

                    CONSOLIDATED STATEMENT OF CAPITALIZATION
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                                             December 31,
(In Thousands of Dollars)                                         2002                 2001               2002              2001
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>                    <C>                    <C>               <C>
Common Shareholders' Equity                                          Shares Issued
Common stock, $0.01 par value                                  158,837,654        158,837,654             $ 1,588           $ 1,588
Premium on capital stock                                                                                3,003,766         2,994,209
Retained earnings                                                                                         522,835           452,206
Other comprehensive income                                                                               (108,423)            4,483
Treasury stock                                                  16,412,880         19,407,905            (475,174)         (561,884)
------------------------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity                              142,424,774        139,429,749           2,944,592         2,890,602
------------------------------------------------------------------------------------------------------------------------------------

Preferred Stock - No Redemption Required
Par Value $100 per share
7.07% Series B -private placement                                  553,000            553,000              55,300            55,300
7.17% Series C-private placement                                   197,000            197,000              19,700            19,700
6.00% Series A-private placement                                    88,486             90,770               8,849             9,077
------------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required                                                             83,849            84,077
------------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt                                          Interest Rate           Maturity
------------------------------------------------------------------------------------------------------------------------------------
Notes
Medium term notes                                         6.15% - 9.75%         2005 - 2030             2,885,000         2,885,000
Senior subordinated notes                                     8.63%                2008                   100,000           100,000
------------------------------------------------------------------------------------------------------------------------------------
Total Notes                                                                                             2,985,000         2,985,000
------------------------------------------------------------------------------------------------------------------------------------
Gas Facilities Revenue Bonds                                Variable               2020                   125,000           125,000
                                                          5.50% - 6.95%         2020 - 2026               523,500           523,500
------------------------------------------------------------------------------------------------------------------------------------
Total Gas Facilities Revenue Bonds                                                                        648,500           648,500
------------------------------------------------------------------------------------------------------------------------------------
Promissory Notes to LIPA
Debentures                                                    8.20%                2023                   270,000           270,000
Pollution control revenue bonds                               5.15%                2016                   108,022           108,022
Electric facilities revenue bonds                         5.30% - 7.15%         2019 - 2025               224,405           224,405
------------------------------------------------------------------------------------------------------------------------------------
Total Promissory Notes to LIPA                                                                            602,427           602,427
------------------------------------------------------------------------------------------------------------------------------------
MEDS Equity Units                                             8.75%                2005                   460,000                 -
First Mortgage Bonds                                     5.50% - 10.10%         2003 - 2028               163,625           179,122
Authority Financing Notes                                   Variable            2027 - 2028                66,005            66,005
Other Subsidiary Debt                                                                                     304,298           330,293
Capital Leases                                                                  2005 - 2022                13,884            15,192
------------------------------------------------------------------------------------------------------------------------------------
Subtotal                                                                                                5,243,739         4,826,539
Unamortized interest rate hedge and debt discount                                                         (75,265)          (80,173)
Derivative impact on debt                                                                                  67,020           (47,724)
Less: current maturities                                                                                   11,413               993
------------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt                                                                                    5,224,081         4,697,649
------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                                                                  $ 8,252,522       $ 7,672,328
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

        See accompanying Notes to the Consolidated Financial Statements.

                                       84

<PAGE>

Notes to the Consolidated Financial Statements

Note 1.  Summary of Significant Accounting Policies

A.  Organization of the Company

KeySpan Corporation, a New York corporation, was formed in May 1998, as a result
of the business  combination  of KeySpan Energy  Corporation,  the parent of The
Brooklyn Union Gas Company,  and certain  businesses of the Long Island Lighting
Company  ("LILCO").  On November 8, 2000,  KeySpan acquired Eastern  Enterprises
("Eastern"),  a  Massachusetts  business  trust,  and the parent of several  gas
utilities operating in Massachusetts. Also on November 8, 2000, Eastern acquired
EnergyNorth,  Inc. ("ENI"), the parent of a gas utility operating in central New
Hampshire.  KeySpan  Corporation  will be  referred  to in  these  notes  to the
Consolidated Financial Statements as "KeySpan", "we", "us" and "our."

Our core  business  is gas  distribution,  conducted  by our six  regulated  gas
utility  subsidiaries:  The  Brooklyn  Union Gas Company  d/b/a  KeySpan  Energy
Delivery  New York  ("KEDNY")  and KeySpan Gas East  Corporation  d/b/a  KeySpan
Energy  Delivery  Long  Island  ("KEDLI")  distribute  gas to  customers  in the
boroughs of  Brooklyn,  Staten  Island and a portion of the borough of Queens in
New York City,  and the  counties  of Nassau and  Suffolk on Long Island and the
Rockaway  Peninsula in Queens,  respectively;  Boston Gas Company,  Colonial Gas
Company and Essex Gas Company,  each doing business as KeySpan  Energy  Delivery
New England  ("KEDNE"),  distribute  gas to customers  in southern,  eastern and
central  Massachusetts;  and EnergyNorth Natural Gas, Inc., d/b/a KeySpan Energy
Delivery New England  distributes  gas to  customers  in central New  Hampshire.
Together,  these companies distribute gas to approximately 2.5 million customers
throughout the Northeast.

We also own, lease and operate electric  generating plants on Long Island and in
New York  City.  Under  contractual  arrangements,  we provide  power,  electric
transmission and distribution services,  billing and other customer services for
approximately 1.1 million electric  customers of the Long Island Power Authority
("LIPA").

Our other  subsidiaries  are involved in gas and oil exploration and production;
gas storage; wholesale and retail gas and electric marketing; appliance service;
heating,  ventilation  and air  conditioning  installation  and services;  large
energy-system ownership,  installation and management; and fiber optic services.
We also invest in, and participate in the  development  of,  pipelines and other
energy-related  projects,   domestically  and  internationally.   (See  Note  2,
"Business Segments" for additional information on each operating segment.)

We are a registered holding company under the Public Utility Holding Company Act
of 1935 ("PUHCA"), as amended. Therefore, our corporate and financial activities
and those of our  subsidiaries,  including their ability to pay dividends to us,
are subject to regulation by the  Securities  and Exchange  Commission  ("SEC").
Under our holding company structure, we have no independent operations or source
of income of our own and conduct all of our operations  through our subsidiaries
and, as a result,  we depend on the earnings and cash flow of, and  dividends or



                                       85
<PAGE>

distributions  from, our subsidiaries to provide the funds necessary to meet our
debt and  contractual  obligations.  Furthermore,  a substantial  portion of our
consolidated  assets,  earnings and cash flow is derived from the  operations of
our regulated  utility  subsidiaries,  whose legal authority to pay dividends or
make other  distributions  to us is subject to  regulation  by state  regulatory
authorities.

B.  Basis of Presentation

The Consolidated  Financial  Statements presented herein reflect the accounts of
KeySpan and its subsidiaries. Most of our subsidiaries are fully consolidated in
the financial information  presented,  except for certain subsidiary investments
in the Energy  Investments  segment which are accounted for on the equity method
as we do not have a controlling  voting  interest or otherwise have control over
the management of such companies. All significant intercompany transactions have
been eliminated.

As noted, on November 8, 2000, we completed the acquisitions of Eastern and ENI.
The transactions have been accounted for using the purchase method of accounting
for  business   combinations  and  accordingly  the  accompanying   consolidated
financial   statements  include  the  results  of  Eastern  and  ENI  since  the
acquisition date.

The preparation of financial  statements in conformity  with Generally  Accepted
Accounting  Principles  ("GAAP")  requires  management  to  make  estimates  and
assumptions  that  affect the  reported  amounts of assets and  liabilities  and
disclosure of  contingent  assets and  liabilities  at the date of the financial
statements  and the  reported  amounts  of  revenues  and  expenses  during  the
reporting period. Actual results could differ from those estimates.

C. Accounting for the Effects of Rate Regulation

The  accounting  records for our six regulated  gas utilities are  maintained in
accordance with the Uniform System of Accounts  prescribed by the Public Service
Commission of the State of New York ("NYPSC"),  the New Hampshire Public Utility
Commission ("NHPUC"), and the Massachusetts Department of Telecommunications and
Energy ("DTE").  Our electric  generation  subsidiaries are not subject to state
rate regulation,  but they are subject to Federal Energy  Regulatory  Commission
("FERC")  regulation.  Our financial  statements reflect the ratemaking policies
and  actions of these  regulators  in  conformity  with GAAP for  rate-regulated
enterprises.

Four of our six regulated gas utilities  (KEDNY,  KEDLI,  Boston Gas Company and
EnergyNorth  Natural Gas,  Inc.) and our Long Island based  electric  generation
subsidiaries are subject to the provisions of Statement of Financial  Accounting
Standards  ("SFAS")  71,  "Accounting  for  the  Effects  of  Certain  Types  of
Regulation."  This statement  recognizes the ability of regulators,  through the
ratemaking process, to create future economic benefits and obligations affecting
rate-regulated companies.  Accordingly, we record these future economic benefits
and  obligations  as  Regulatory  Assets  and  Regulatory   Liabilities  on  the
Consolidated Balance Sheet, respectively.


                                       86
<PAGE>

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

The following table presents our net regulatory assets at December 31, 2002 and
December 31, 2001.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------
                                                                                December 31,
(In Thousands of Dollars)                                                 2002                2001
-----------------------------------------------------------------------------------------------------
Regulatory Assets
<S>                                                                     <C>                 <C>
 Regulatory tax asset                                                   $ 53,401            $ 64,536
 Property taxes                                                           58,400              54,617
 Environmental costs                                                     182,163             183,716
 Postretirement benefits other than pensions                              82,563              84,238
 Costs associated with the KeySpan/LILCO transaction                      61,989              55,204
 Derivative assets                                                             -              15,880
----------------------------------------------------------------------------------------------------
Total Regulatory Assets                                                $ 438,516           $ 458,191
Regulatory Liabilities                                                   (84,479)            (39,442)
----------------------------------------------------------------------------------------------------
Net Regulatory Assets                                                  $ 354,037           $ 418,749
----------------------------------------------------------------------------------------------------
</TABLE>

The regulatory  assets above are not included in rate base.  However,  we record
carrying charges on the property tax and costs associated with the KeySpan/LILCO
transaction  cost deferrals.  We also record carrying  charges on our regulatory
liabilities.  The remaining  regulatory assets represent,  primarily,  costs for
which  expenditures have not yet been made, and therefore,  carrying charges are
not recorded. We anticipate recovering these costs in our gas rates concurrently
with future cash  expenditures.  If  recovery  is not  concurrent  with the cash
expenditures, we will record the appropriate level of carrying charges. Deferred
gas costs of $61.8  million and $5.6  million at December  31, 2002 and December
31, 2001,  respectively are reflected in Accounts Receivable on the Consolidated
Balance  Sheet.  Deferred  gas  costs  are  subject  to  current  recovery  from
customers.

We  estimate  that full  recovery  of our  regulatory  assets will not exceed 15
years,  except for the  regulatory  tax asset,  which will be recovered over the
estimated lives of certain utility property.

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  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 all or a portion of our existing  regulatory  assets
and  liabilities  could  result.  If we were  unable  to  continue  to apply the
provisions of SFAS 71 for any of our rate regulated subsidiaries, we would apply
the  provisions  of  SFAS  101,  "Regulated  Enterprises  -  Accounting  for the
Discontinuation  of  Application  of FASB  Statement  71." We estimate  that the
write-off of all regulatory assets at December 31, 2002 could result in a charge
to net income of $230.1 million or $1.63 per share, which would be classified as
an extraordinary item. In management's opinion, our regulated  subsidiaries that
are currently  subject to the  provisions of SFAS 71 will continue to be subject
to SFAS 71 for the foreseeable future.


                                       87
<PAGE>

D.  Revenues

Gas  Distribution:  Utility gas customers are billed  monthly or bi-monthly on a
cycle basis.  Revenues  include  unbilled  amounts  related to the estimated gas
usage that occurred from the most recent meter reading to the end of each month.

The cost of gas used is  recovered  when  billed to firm  customers  through the
operation of gas adjustment clauses ("GAC") included in utility tariffs. The GAC
provision  requires  periodic  reconciliation  of recoverable  gas costs and GAC
revenues.  Any  difference is deferred  pending  recovery from or refund to firm
customers.  Further, net revenues from tariff gas balancing services, off-system
sales and certain on-system interruptible sales are refunded, for the most part,
to firm customers subject to certain sharing provisions.

The New York and Long Island gas utility tariffs  contain weather  normalization
adjustments  that  largely  offset  shortfalls  or excesses of firm net revenues
(revenues  less gas costs and  revenue  taxes)  during a heating  season  due to
variations from normal  weather.  Revenues are adjusted each month the clause is
in effect and are generally  included in rates in the following  month.  The New
England gas utility rate structures  contain no weather  normalization  feature,
therefore their net revenues are subject to weather related demand fluctuations.

Electric  Services:  Electric  revenues  are derived  from  billings to LIPA for
management of LIPA's  transmission  and  distribution  ("T&D") system,  electric
generation, and procurement of fuel. The agreements with LIPA include provisions
for us to earn, in the aggregate,  approximately $11.5 million per year (plus up
to an  additional  $5 million per year if certain cost savings are  achieved) in
annual  management  service fees from LIPA for the  management of the T&D system
and the  management of all aspects of fuel and power supply.  Under a Management
Service  Agreement  ("MSA") costs in excess of budgeted levels are assumed by us
up to $15 million,  while cost  reductions in excess of $5 million from budgeted
levels are shared with LIPA.  These  agreements  also contain  certain  non-cost
incentive and penalty  provisions which could impact  earnings.  Rates billed to
LIPA on a monthly basis include fixed and variable components.  Billings related
to  transmission,  distribution  and delivery  services are based,  in part,  on
negotiated estimated levels.

KeySpan  Glenwood Energy Center LLC and KeySpan Port Jefferson Energy Center LLC
have  entered into 25 year Power  Purchase  Agreements  with LIPA (the  "PPAs").
Under the terms of the PPAs, these subsidiaries sell capacity, energy conversion
services  and  ancillary  services to LIPA.  Both plants are designed to produce
79.9 megawatts  ("MW").  Under the PPAs, LIPA pays a monthly capacity fee, which
guarantees  full  recovery of each  plant's  construction  costs,  as well as an
appropriate rate of return on investment. The PPAs also obligate LIPA to pay for
each plant's  costs of operation  and  maintenance.  These costs are billed on a
monthly estimated basis and are subject to true up for actual costs incurred.

In addition,  electric  revenues are derived  from our  investment  in the 2,200
megawatt Ravenswood electric generation facility ("Ravenswood facility"),  which
we  acquired  in June  1999.  (See Note 7  "Contractual  Obligations,  Financial
Guarantees and Contingencies" for a description of the Ravenswood  transaction.)


                                       88
<PAGE>

We realize  revenues from our investment in the Ravenswood  facility through the
sale, at wholesale, of energy,  capacity, and ancillary services to the New York
Independent  System Operator  ("NYISO").  Energy and ancillary services are sold
through a bidding  process into the NYISO energy  markets on a day ahead or real
time basis.

Energy  Services:  Revenues earned by our Energy Services segment for mechanical
and   other   contracting    services   are   generally    recognized   by   the
percentage-of-completion  method.  This method  measures the percentage of costs
incurred and accrued to date for each contract to the estimated  total costs for
each contract at  completion.  Provisions  for estimated  losses on  uncompleted
contracts  are made in the period  such  losses are  determined.  Changes in job
performance,  job conditions and estimated profitability may result in revisions
to cost and income,  which are  recognized  in the period in which the revisions
are determined.  The percentage of completion method of accounting may result in
situations  where billings to customers are in excess of costs incurred to date.
These excess  billings are not recognized in income until the related costs have
been  incurred  and the earnings  process is complete.  At December 31, 2002 and
December 31, 2001 we had billings in excess of costs of $27.2  million and $53.6
million, respectively. These balances are included in Accounts Payable and Other
Liabilities on the Consolidated Balance Sheet and are expected to be included in
income within one year.

Energy  service and  maintenance  revenues are  recognized as earned or over the
life of the service contract, as appropriate.  Energy sales made by our electric
and  gas  marketing  subsidiary  are  recorded  upon  delivery  of  the  related
commodity.  Fiber optic service  revenue is recognized  upon delivery of service
access.  We have  unearned  revenue  recorded  in  Deferred  Credits  and  Other
Liabilities - Other on the Consolidated Balance Sheet totaling $19.2 million and
$18.0  million for the years ended  December  31, 2002 and  December  31,  2001,
respectively.  These balances  represent unearned revenues for service contracts
and leases on our fiber optic  cables.  The unearned  revenues  from the service
contracts  are generally  amortized to income  within one year,  while the lease
related  unearned  revenues are amortized over periods  ranging from seven to 30
years.

Gas Exploration  and Production:  Natural gas and oil revenues earned by our gas
exploration  and  production  activities  is recognized  using the  entitlements
method of accounting. Under this method of accounting,  income is recorded based
on the net revenue  interest in production or nominated  deliveries.  Production
gas volume  imbalances  are  incurred in the ordinary  course of  business.  Net
deliveries in excess of entitled amounts are recorded as liabilities,  while net
under  deliveries  are  recorded as assets.  Imbalances  are  reduced  either by
subsequent  recoupment of over and under  deliveries or by cash  settlement,  as
required by applicable contracts.  Production imbalances are marked-to-market at
the end of each month using the market price at the end of each period.


                                       89
<PAGE>

E. Utility and Other Property - Depreciation and Maintenance

Property,  principally  utility  gas  property  is  stated at  original  cost of
construction,  which includes allocations of overheads,  including taxes, and an
allowance  for  funds  used  during  construction.  The  rates at which  KeySpan
subsidiaries capitalized interest for years ended December 31, 2000 through 2002
ranged from 3.44% to 10.67%.  Capitalized  interest for 2002,  2001 and 2000 was
$19.7 million, $8.5 million and $2.7 million respectively.

Depreciation  is  provided on a  straight-line  basis in amounts  equivalent  to
composite rates on average depreciable  property.  The cost of property retired,
plus the cost of removal less salvage,  is charged to accumulated  depreciation.
The cost of repair and minor  replacement  and renewal of property is charged to
maintenance expense. The composite rates on average depreciable property were as
follows:

----------------------------------------------------------------------------
                                             Year Ended December 31,
                                       2002           2001            2000
----------------------------------------------------------------------------
Electric                               3.88%           3.78%          3.68%
Gas                                    3.44%           3.40%          3.51%
----------------------------------------------------------------------------


We also had $394.4 million of other property at December 31, 2002,  which is not
recovered under rate orders.  This property consists of assets held primarily by
our Corporate  Service  subsidiary of $312.6 million and $81.8 million in Energy
Services  assets.   The  Corporate  Service  assets  consist  largely  of  land,
buildings,   office   equipment   and   furniture,    vehicles,   computer   and
telecommunications  equipment and systems.  These assets have depreciable  lives
ranging  from  three to 40 years.  Energy  Service  assets  consist  largely  of
construction  equipment and fiber optic cable and related  electronics  and have
service lives ranging from seven to 40 years.

KeySpan's repair and maintenance  costs,  including planned major maintenance in
the Electric Services segment for turbine and generator overhauls,  are expensed
as incurred.  Planned major  maintenance  cycles  primarily  range from seven to
eight years.  Smaller periodic  overhauls are performed  approximately  every 18
months.

F.  Gas Exploration and Production Property - Depletion

At December 31, 2002, we had exploration  and production  property in the amount
of $2.4 billion  related to our  investments in natural gas and oil  properties.
These assets are accounted for under the full cost method of  accounting.  Under
the full cost method,  costs of  acquisition,  exploration  and  development  of
natural  gas  and oil  reserves  are  capitalized  into a "full  cost  pool"  as
incurred.   Unproved   properties  and  related  costs  are  excluded  from  the
amortization  base until a determination as to the existence of proved reserves.
Properties  are depleted and charged to operations  using the unit of production
method using proved reserve quantities.

These investments  consist of our ownership 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


                                       90
<PAGE>

approximately 56% following the repurchase, by Houston Exploration, of 3 million
shares of stock owned by KeySpan. To the extent that such capitalized costs (net
of accumulated  depletion) less deferred taxes exceed the present value (using a
10% discount  rate) of estimated  future net cash flows from proved  natural gas
and oil  reserves  and the lower of cost or fair value of  unproved  properties,
less  deferred  taxes,  such  excess  costs are  charged  to  operations.  If an
impairment  is  required,  it would result in a charge to earnings but would not
have an impact on cash flows.  Once incurred,  such impairment of gas properties
is not reversible at a later date even if gas prices increase.

The ceiling test is calculated  using natural gas and oil prices in effect as of
the  balance  sheet  date,  held  flat  over  the life of the  reserves.  We use
derivative  financial  instruments  that qualify for hedge accounting under SFAS
133 "Accounting for Derivative Instruments and Hedging Activities", to hedge the
volatility of natural gas prices. In accordance with current SEC guidelines,  we
have  included  estimated  future  cash  flows from our  hedging  program in the
ceiling  test  calculation.  As of December  31,  2002,  we  estimated,  using a
wellhead price of $4.99 per mcf, that our  capitalized  costs did not exceed the
ceiling test limitation.

In  calculating  the ceiling test at December 31, 2001,  we  estimated,  using a
wellhead price of $2.38 per mcf, that our capitalized costs exceeded the ceiling
limitation.  As a result,  in the fourth  quarter of 2001,  we  recorded a $42.0
million  impairment  charge to write down  our gas  exploration  and  production
assets, and recorded this charge in Depreciation,  Depletion and Amortization on
the  Consolidated  Statement of Income.  Our share of the impairment  charge was
$26.2 million after-tax, or $0.19 per share.

Natural gas prices continue to be volatile and the risk that we will be required
to write down our full cost pool increases when, among other things, natural gas
prices are depressed,  we have significant  downward  revisions in our estimated
proved reserves or we have unsuccessful drilling results.

Houston Exploration  capitalizes interest related to its unevaluated natural gas
and oil properties,  as well as some properties under  development which are not
currently  being  amoritized.  For years ended December 31, 2002, 2001 and 2000,
capitalized  interest  was  $8.0  million,  $12.0  million  and  $13.7  million,
respectively.

G.  Goodwill

At  December  31,  2002 and 2001,  the  balance of  goodwill  was $1.8  billion,
representing  the excess of  acquisition  cost over the fair value of net assets
acquired.  Our recorded goodwill, net of accumulated  amortization,  consists of
$1.5 billion related to the Eastern and ENI  acquisitions,  $156 million related
to the KeySpan/LILCO  transaction,  and $176 million related to the acquisitions
of energy-related service companies and to certain ownership interests of 50% or
less in  energy-related  investments in Northern Ireland which are accounted for
under the equity method.

On January 1, 2002,  KeySpan  adopted SFAS 142  "Goodwill  and Other  Intangible
Assets".  Under SFAS 142, among other things,  goodwill is no longer required to
be amortized and is to be tested for impairment at least  annually.  The initial
impairment test was to be performed within six months of adopting SFAS 142 using
a  discounted  cash flow  method,  compared to a  undiscounted  cash flow method
allowed under a previous standard. Any amounts impaired using data as of January


                                       91
<PAGE>

1, 2002,  was to be recorded as a "Cumulative  Effect of an Accounting  Change".
Any amounts impaired using data after the initial adoption date will be recorded
as an operating  expense.  During the second  quarter of 2002,  we completed our
initial  impairment  analysis for all the reporting units and determined that no
consolidated  impairment  existed.  Also, in the fourth quarter of 2002, KeySpan
updated its review of the carrying value of goodwill  compared to the fair value
of the assets by reporting unit and determined that no impairment existed.

As  required  by SFAS  142,  below  is a  reconciliation  of  reported  earnings
available for common  stockholders  for the years ended December 31, 2002,  2001
and 2000 and  pro-forma  net  income,  for the same  periods,  adjusted  for the
discontinuance of goodwill amortization.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                                                                             Year Ended December 31,
(In Thousands of Dollars, Except for Per Share Amounts)                            2002                2001                2000
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>                 <C>                 <C>
Earnings  for common stockholders                                               $ 371,935           $ 218,350           $ 282,694
Add back: goodwill amortization*                                                        -              49,550              19,690
----------------------------------------------------------------------------------------------------------------------------------
Adjusted net income                                                             $ 371,935           $ 267,900           $ 302,384
----------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share                                                             2.63                1.58                2.10
Add back: goodwill amortization                                                         -                0.36                0.15
----------------------------------------------------------------------------------------------------------------------------------
Adjusted basic earnings per share                                                  $ 2.63              $ 1.94              $ 2.25
----------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share                                                         $ 2.61              $ 1.56                2.09
Add back: goodwill amortization                                                         -                0.36                0.15
----------------------------------------------------------------------------------------------------------------------------------
Adjusted diluted earnings per share                                                $ 2.61              $ 1.92              $ 2.24
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
*    Excludes the write-off of $12.4 million of goodwill in 2001 associated with
     the Roy Kay Operations.

For the twelve months ended  December 31, 2001 and 2000,  respectively  goodwill
amortization was recorded in each segment as follows: Gas Distribution $35.6 and
$5.9 million;  Energy Services $8.2 and $7.6 million; and Energy Investments and
other $5.8 and $6.2 million. The increase in amortization expense in 2001 versus
2000 primarily reflects the acquisition of Eastern and ENI in November 2000.

Prior to  implementation of SFAS 142, goodwill was reviewed for impairment under
SFAS 121 "Accounting for the Impairment of Long-Lived  Assets and for Long-Lived
Assets to be Disposed  Of".  Under SFAS 121, the  carrying  value of goodwill is
reviewed if the facts and circumstances,  such as significant declines in sales,
earnings or cash flows,  or material  adverse  changes in the business  climate,
suggest it might be  impaired.  If this review  indicates  that  goodwill is not
recoverable,  as determined based upon the estimated  undiscounted cash flows of
the entity  acquired,  impairment  would be measured by  comparing  the carrying
value of the  investment  in such entity to its fair value.  Fair value would be
determined based on quoted market values,  appraisals, or discounted cash flows.
For the year ended  December 31, 2001,  we reviewed the facts and  circumstances
for the  entities  carrying  goodwill  and as a result of the above  procedures,
wrote off $12.4 million associated with the Roy Kay Companies upon determination
that the  asset was not  recoverable.  (See Note 10,  "Roy Kay  Operations"  for
additional information.)


                                       92
<PAGE>

H.  Hedging and Derivative Financial Instruments

From time to time, we employ  derivative  instruments  to hedge a portion of our
exposure to  commodity  price risk and interest  rate risk,  as well as to hedge
cash flow  variability  associated  with a portion of our peak  electric  energy
sales.  Whenever hedge positions are in effect, we are exposed to credit risk in
the event of nonperformance by counter-parties to derivative contracts,  as well
as nonperformance by the counter-parties of the transactions  against which they
are hedged. We believe that the credit risk related to the futures,  options and
swap  instruments is no greater than that associated with the primary  commodity
contracts which they hedge. Our derivative  instruments do not qualify as energy
trading contracts as defined by current accounting literature.

Financially-Settled  Commodity  Derivative  Instruments:  We  employ  derivative
financial  instruments,  such as futures,  options and swaps, for the purpose of
hedging the cash flow variability associated with forecasted purchases and sales
of various  energy-forecasted  commodities.  All such derivative instruments are
accounted  for  pursuant  to  the  requirements  of  SFAS  133  "Accounting  for
Derivative  Instruments  and  Hedging  Activities",  as  amended  by  SFAS  138,
"Accounting  for  Certain   Derivative   Instruments  and  Hedging   Activities"
(collectively,   "SFAS  133").  With  respect  to  those  commodity   derivative
instruments  that are  designated  and  accounted  for as cash flow hedges,  the
effective  portion of  periodic  changes in the fair  market  value of cash flow
hedges is recorded as Other  Comprehensive  Income on the  Consolidated  Balance
Sheet, while the ineffective portion of such changes in fair value is recognized
in  earnings.  Gains and losses (on such cash flow  hedges) that are recorded as
Other   Comprehensive   Income  are  subsequently   reclassified  into  earnings
concurrent with when hedged transactions impact earnings.  With respect to those
commodity derivative instruments that are not designated as hedging instruments,
such  derivatives  are accounted for on the  Consolidated  Balance Sheet at fair
value, with all changes in fair value reported in earnings.

Firm Gas  Sales  Derivatives  Instruments  -  Regulated  Utilities:  We  utilize
derivative financial instruments to reduce cash flow variability associated with
the  purchase  price for a portion  of our future  natural  gas  purchases.  Our
strategy is to minimize  fluctuations  in firm gas sales prices to our regulated
firm gas sales customers in our New York and New Hampshire service  territories.
Since these  derivative  instruments are being employed to support our gas sales
prices  to  regulated  firm  gas  sales  customers,  the  accounting  for  these
derivative  instruments is subject to SFAS 71. Therefore,  changes in the market
value of these  derivatives  are  recorded as a Regulatory  Asset or  Regulatory
Liability on our Consolidated  Balance Sheet.  Gains or losses on the settlement
of these contracts are initially deferred and then refunded to or collected from
our firm gas sales  customers  during  the  appropriate  winter  heating  season
consistent with regulatory requirements.

Physically-Settled Commodity Derivative Instruments:  Upon our implementation of
Derivative  Implementation  Group ("DIG") Issue C16 on April 1, 2002, certain of
our  contracts  for the  physical  purchase of natural  gas were  assessed as no
longer being exempt from the  requirements of SFAS 133 as normal  purchases.  As
such,  these  contracts are recorded on the  Consolidated  Balance Sheet at fair


                                       93
<PAGE>

market value.  However,  since such contracts were executed for the purchases of
natural gas that is sold to regulated firm gas sales customers,  and pursuant to
the requirements of SFAS 71, changes in the fair market value of these contracts
are recorded as a Regulatory  Asset or Regulatory  Liability on the Consolidated
Balance Sheet.

Weather  Derivatives:  The utility  tariffs  associated with our New England gas
distribution operations do not contain a weather normalization  adjustment. As a
result,  fluctuations  from normal  weather may have a  significant  positive or
negative  effect on the results of these  operations.  To mitigate the effect of
fluctuations  from normal weather on our financial  position and cash flows,  we
may enter into derivative  instruments  from time to time. Based on the terms of
the contracts,  we account for these instruments pursuant to the requirements of
EITF 99-2 "Accounting for Weather  Derivatives." In this regard,  we account for
weather  derivatives  using the  "intrinsic  value  method" as set forth in such
guidance.

Interest  Rate   Derivative   Instruments:   We  continually   assess  the  cost
relationship between fixed and variable rate debt. Consistent with our objective
to minimize capital costs, we periodically enter into hedging  transactions that
effectively  convert  the terms of  underlying  debt  obligations  from fixed to
variable  or variable to fixed.  Payments  made or received on these  derivative
contracts  are  recognized  as an  adjustment  to interest  expense as incurred.
Hedging  transactions  that  effectively  convert the terms of  underlying  debt
obligations  from  fixed  to  variable  are  designated  and  accounted  for  as
fair-value hedges pursuant to the requirements of SFAS 133. Hedging transactions
that effectively  convert the terms of underlying debt obligations from variable
to fixed are considered cash flow hedges.

I.  Equity Investments

Certain  subsidiaries  own as their  principal  assets,  investments  (including
goodwill)  representing  ownership  interests  of 50% or less in  energy-related
businesses  that are  accounted  for  under  the  equity  method.  None of these
investments are publicly traded.

J.  Income and Excise Tax

In accordance  with SFAS 109,  "Accounting for Income Taxes" and applicable rate
regulation,  certain of our regulated subsidiaries record a regulatory asset for
the net cumulative effect of providing  deferred income taxes on all differences
between  the  financial  statement  carrying  amounts  of  existing  assets  and
liabilities,  and their respective tax basis. Investment tax credits, which were
available  prior to the Tax  Reform Act of 1986,  were  deferred  and  generally
amortized as a reduction of income tax over the  estimated  lives of the related
property.

We report our  collections  and payments of excise  taxes on a gross basis.  Gas
distribution  revenues  include the collection of excise taxes,  while operating
taxes include the related  expense.  For the years ended December 31, 2002, 2001
and 2000, excise taxes collected and paid were $98.2 million, $119.1 million and
$117.8 million, respectively.


                                       94
<PAGE>

K.  Subsidiary Common Stock Issuances to Third Parties

We  follow an  accounting  policy of income  statement  recognition  for  parent
company  gains or losses  from  issuances  of common  stock by  subsidiaries  to
unaffiliated third parties.

L.  Foreign Currency Translation

We  follow  the  principles  of SFAS 52,  "Foreign  Currency  Translation,"  for
recording our  investments  in foreign  affiliates.  Under this  statement,  all
elements of the financial  statements are translated by using a current exchange
rate.  Translation  adjustments  result from changes in exchange  rates from one
reporting  period to  another.  At  December  31,  2002,  the  foreign  currency
translation  adjustment  was  included  in  Other  Comprehensive  Income  on the
Consolidated  Balance Sheet. The functional  currency for our foreign affiliates
is their local currency.

M.  Earnings Per Share

Basic  earnings per share ("EPS") is calculated by dividing  earnings 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 for common stock, as adjusted,
by the sum of the weighted average number of shares of common stock  outstanding
plus all potentially dilutive securities.

At December 31, 2002 we have  approximately  2.1 million options  outstanding to
purchase  KeySpan common stock that were not used in the  calculation of diluted
EPS since the exercise price  associated with these options was greater than the
average per share market  price of  KeySpan's  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 years  ending  December  31, 2001 and 2000,
since to do so would have been anti-dilutive.







                                       95
<PAGE>


Under the  requirements of SFAS 128,  "Earnings Per Share" our basic and diluted
EPS are as follows:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
                                                                                           Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts)                              2002                2001                2000
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>                  <C>                 <C>
Earnings for common stock                                                    $ 371,935            $ 218,350           $ 282,694
Houston Exploration dilution                                                      (471)              (1,116)               (725)
Preferred stock dividend                                                           531                    -                   -
--------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted                                         $ 371,995            $ 217,234           $ 281,969
--------------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000)                                      141,263              138,214             134,357
Add dilutive securities:
Options                                                                            809                1,007                 808
Convertible preferred stock                                                        228                    -                   -
--------------------------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution                  142,300              139,221             135,165
--------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share                                                     $    2.63            $    1.58           $    2.10
--------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share                                                   $    2.61            $    1.56           $    2.09
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>

N.  Stock Options

We issue stock  options to all KeySpan  officers  and certain  other  management
employees 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.  Up to
approximately  19.3  million  shares have been  authorized  for the  issuance of
options and approximately 6.7 million of these shares were remaining at December
31,  2002.  Moreover,  under a separate  plan,  Houston  Exploration  has issued
approximately  2.4 million stock options to key Houston  Exploration  employees.
During  2002,   we  announced  our  intention  to  record  stock  options  as  a
compensation  expense beginning with those options granted in 2003.  KeySpan and
Houston  Exploration  have  adopted  the  prospective  method of  transition  in
accordance with SFAS 148  "Accounting for Stock-Based  Compensation - Transition
and  Disclosure".  Accordingly,  compensation  expense  will  be  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  will  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:


                                       96
<PAGE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                                Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts)                                    2002               2001              2000
-----------------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock:
<S>                                                                                 <C>               <C>                <C>
As reported                                                                         $ 371,935         $ 218,350          $ 282,694
     Add: recorded stock-based compensation expense, net of tax                           221               261                195
     Deduct: total stock-based compensation expense, net of tax                        (7,547)           (8,459)            (6,835)
-----------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings                                                                  $ 364,609         $ 210,152          $ 276,054
-----------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
     Basic - as reported                                                            $    2.63         $    1.58          $    2.10
     Basic - pro-forma                                                              $    2.58         $    1.52          $    2.05

     Diluted - as reported                                                          $    2.61         $    1.56          $    2.09
     Diluted - pro-forma                                                            $    2.56         $    1.50          $    2.04
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


All grants are estimated on the date of the grant using the Black-Scholes
option-pricing model. The following table presents the weighted average fair
value, exercise price and assumptions used for the periods indicated:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
                                                                  Year Ended December 31,
                                                        2002                 2001                 2000
--------------------------------------------------------------------------------------------------------
<S>                                                 <C>                  <C>                   <C>
Fair value of grants issued                         $    3.42            $    5.29             $   2.87
Dividend yield                                          5.36%                4.91%                8.22%
Expected volatility                                    22.47%               29.04%               24.00%
Risk free rate                                          4.94%                5.13%                6.54%
Expected lives                                       10 years             10 years              6 years
Exercise price                                      $   32.66            $   39.50             $  22.69
--------------------------------------------------------------------------------------------------------
</TABLE>


A summary of the status of our fixed stock option plans and changes is presented
below for the periods indicated:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                           Year Ended December 31,
                                                      2002                           2001                          2000
----------------------------------------------------------------------------------------------------------------------------------
                                                             Weighted                         Weighted                    Weighted
                                                             Exercise                         Exercise                    Exercise
                   Fixed Options             Shares           Price         Shares             Price         Shares        Price
----------------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                 <C>          <C>                <C>         <C>             <C>
Outstanding at beginning of period         7,796,162         $ 29.67        6,456,627         $ 25.61       4,968,398     $ 28.81
Granted during the year                    2,796,310         $ 32.66        2,285,350         $ 39.50       3,165,822     $ 22.69
Exercised                                   (506,794)        $ 24.42         (809,983)        $ 25.15      (1,577,259)    $ 27.82
Forfeited                                   (560,778)        $ 30.99         (135,832)        $ 29.19        (100,334)    $ 26.04
----------------------------------------------------------------------------------------------------------------------------------
Outstanding at end of period               9,524,900         $ 30.74        7,796,162         $ 29.67       6,456,627     $ 25.61
----------------------------------------------------------------------------------------------------------------------------------
Exercisable at end of period               4,105,999         $ 27.69        2,996,771         $ 24.86       2,759,599     $ 29.57
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       97
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                       Options          Weighted                                  Options            Weighted
Remaining            Outstanding         Average                                Exercisable at        Average
Contractual          December 31,       Exercise      Range of Exercise          December 31,        Exercise    Range of Exercise
Life                     2002             Price            price                    2002               Price          price
------------------------------------------------------------------------------------------------------------------------------------
<S>               <C>                    <C>         <C>                        <C>                   <C>       <C>
 2 years                2,644            $ 13.76          $13.76                     2,644            $ 13.76        $13.76
 3 years               30,138            $ 25.98      $14.86 - 27.00                30,138            $ 25.98    $14.86 - 27.00
 4 years              226,086            $ 30.43      $20.57 - 32.63               226,086            $ 30.43    $20.57 - 32.63
 5 years              304,410            $ 32.56      $19.15 - 32.63               304,410            $ 32.56    $19.15 - 32.63
 6 years            1,457,104            $ 27.78      $24.73 - 29.38             1,457,104            $ 27.78    $24.73 - 29.38
 7 years              717,314            $ 26.82      $21.99 - 27.06               717,314            $ 26.82    $21.99 - 27.06
 8 years            2,048,335            $ 22.71      $22.50 - 32.76             1,019,117            $ 22.71    $22.50 - 32.76
 9 years            2,068,928            $ 39.50          $39.50                   349,186            $ 39.50        $39.50
 10 years           2,669,941            $ 32.66          $32.66                         -            $ 32.66        $32.66
------------------------------------------------------------------------------------------------------------------------------------
                    9,524,900                                                    4,105,999
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


In early March 2003, KeySpan's Board of Directors approved a modification to the
Long-Term  Incentive  Compensation  Plan  and its  application  to  officers  of
KeySpan. During 2003, long-term incentive compensation for officers will consist
of 50% stock  options and 50%  performance  shares.  Performance  shares will be
awarded based upon the  attainment of overall  corporate  performance  goals and
will better align incentive  compensation  with overall  corporate  performance.
During  2002,  and  in  prior  years,   the  majority  of  long-term   incentive
compensation awards were stock option grants with a limited amount of restricted
stock award grants.

O.  Recent Accounting Pronouncements

On January 1, 2002, we adopted SFAS 141, "Business  Combinations",  and SFAS 142
"Goodwill  and  Other  Intangible  Assets".   The  key  concepts  from  the  two
interrelated  Statements  include  mandatory  use of the  purchase  method  when
accounting for business combinations, discontinuance of goodwill amortization, a
revised  framework for testing  goodwill  impairment at a "reporting unit" level
and new criteria for the  identification  and  potential  amortization  of other
intangible assets.  Other changes to existing  accounting  standards involve the
amount of goodwill to be used in determining the gain or loss on the disposal of
assets and a requirement to test goodwill for impairment at least annually.  See
Item G "Goodwill" for a discussion of goodwill impairment testing.

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

KeySpan has  completed  its  assessment  of SFAS 143. At December 31,  2002,  we
estimate  that the  present  value of our  future  Asset  Retirement  Obligation
("ARO") is  approximately  $57 million,  primarily  related to our investment in
Houston Exploration.  We estimate that the cumulative effect of SFAS 143 and the
change in accounting principle will be a benefit to net income of $49.5 million,
or  $32.2  million,   after-tax.   KeySpan's  largest  asset  base  is  its  gas



                                       98
<PAGE>

transmission  and  distribution  system.  A legal obligation may be construed to
exist due to certain safety  requirements at final abandonment.  In addition,  a
legal  obligation may be construed to exist with respect to KeySpan's  liquefied
natural  gas  ("LNG")  storage  tanks  due to  clean  up  responsibilities  upon
cessation  of use.  However,  mass  assets  such as  storage,  transmission  and
distribution assets are believed to operate in perpetuity and,  therefore,  have
indeterminate  cash flow  estimates.  Since that exposure is in  perpetuity  and
cannot  be  measured,  no  liability  will be  recorded.  KeySpan's  ARO will be
re-evaluated in future periods until sufficient  information exists to determine
a reasonable estimate of fair value.

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

In June of 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with
Exit or Disposal Activities".  This Statement addresses financial accounting and
reporting for costs  associated  with exit or disposal  activities and nullifies
EITF 94-3, "Liability  Recognition for Certain Employee Termination Benefits and
Other  Costs to Exit an  Activity".  This  Statement  is  effective  for exit or
disposal  activities  initiated after December 31, 2002, with early  application
encouraged.

In December  of 2002,  the FASB issued  SFAS 148,  "Accounting  for  Stock-Based
Compensation-Transition and Disclosure",  which amends SFAS 123, "Accounting for
Stock-Based  Compensation".  This  Statement  provides  alternative  methods  of
transition  for a voluntary  change to the fair value based method of accounting
for  stock-based  employee  compensation.  In  addition,  SFAS  148  amends  the
disclosure  requirements of SFAS 123 to require more prominent and more frequent
disclosures   in  financial   statements   about  the  effects  of   stock-based
compensation.  See Item N "Stock Options" for these disclosures.  The transition
guidance and annual  disclosure  provisions of SFAS 148 are effective for fiscal
years ending after  December 15,  2002,  with earlier  application  permitted in
certain  circumstances.  The interim  disclosure  provisions  are  effective for
financial reports containing  financial statements for interim periods beginning
after December 15, 2002.


                                       99
<PAGE>

The recognition provisions of this Statement allow for three alternative methods
of recognizing stock-based employee compensation expense. KeySpan has elected to
follow the prospective  method of recognizing an expense for all employee awards
granted  or  modified  after  January  1,  2003.  The  expense  associated  with
implementation of this method is not expected to be material in 2003.

In  November  2002,  the FASB  issued  FASB  Interpretation  No. 45 ("FIN  45"),
"Guarantor's  Accounting and Disclosure  Requirements for Guarantees,  Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires the guarantor to
recognize a liability for the non-contingent component of a guarantee;  that is,
the obligation to stand ready to perform in the event that specified  triggering
events or conditions  occur.  The initial  measurement  of this liability is the
fair value of the guarantee at inception.  The  recognition  of the liability is
required even if it is not probable  that  payments  will be required  under the
guarantee or if the guarantee was issued with a premium  payment or as part of a
transaction with multiple elements.  FIN 45 also requires additional disclosures
related to guarantees (See Note 7 "Contractual Obligations, Financial Guarantees
and Contingencies" for a description of KeySpan's outstanding  guarantees).  The
disclosure   requirements   are  effective  for  interim  and  annual  financial
statements  for periods  ending after  December 15, 2002.  The  recognition  and
measurement  provisions of FIN 45 are effective for all guarantees  entered into
or modified  after  December 31,  2002.  We  currently  do not  anticipate  that
implementation  of this Statement will have a significant  effect on our results
of operations and financial condition.

In  January  2003,  the FASB  issued  FASB  Interpretation  No.  46 ("FIN  46"),
"Consolidation of Variable Interest Entities,  an Interpretation of ARB No. 51."
FIN 46 requires  certain  variable  interest  entities to be consolidated by the
primary  beneficiary of the entity if the equity  investors in the entity do not
have the  characteristics  of a  controlling  financial  interest or do not have
sufficient  equity at risk for the  entity to  finance  its  activities  without
additional  subordinated  financial  support  from  other  parties.  FIN  46  is
effective  for all new  variable  interest  entities  created or acquired  after
January 31, 2003. For variable  interest  entities  created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period beginning after June 15, 2003. We currently have an arrangement
with a  variable  interest  entity  through  which  we  lease a  portion  of the
Ravenswood facility (See Note 7 "Contractual  Obligations,  Financial Guarantees
and Contingencies" for a description of the Ravenswood transaction).





                                       100
<PAGE>

Note 2. Business Segments

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

The Gas Distribution segment consists of our six gas distribution  subsidiaries.
KEDNY  provides  gas  distribution  services to  customers  in the New York City
boroughs  of  Brooklyn,  Staten  Island and a portion of the  borough of Queens.
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,  collectively doing business as 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.
The Electric  Services  segment also includes  subsidiaries  that own, lease and
operate the 2,200 megawatt  Ravenswood  electric  generation facility located in
Queens, New York. All of the energy,  capacity and ancillary services related to
the Ravenswood facility is sold to the NYISO energy markets.  Further,  two 79.9
megawatt  generating  facilities located on Long Island were placed into service
in June and July 2002.  The  capacity  of and energy from these  facilities  are
dedicated to LIPA under 25 year contracts.

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

The Energy  Investments  segment  consists of our gas exploration and production
investments, as well as certain other domestic and international  energy-related
investments.  Our gas exploration and production subsidiaries are engaged in gas
and oil  exploration  and  production,  and the  development  and acquisition of
domestic  natural  gas and oil  properties.  These  investments  consist  of our
ownership interest in 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.  As
previously mentioned, on February 26, 2003, we reduced our ownership interest in
Houston  Exploration from 66% to approximately 56% following the repurchase,  by
Houston Exploration, of 3 million shares of stock owned by KeySpan. We realized


                                       101
<PAGE>

$79  million  in  connection  with this  repurchase.  Additionally,  there is an
over-allotment  option for 300,000  shares,  which if  exercised,  would further
reduce our ownership in Houston Exploration to 55%. Subsidiaries in this segment
also hold a 20% equity  interest in the Iroquois Gas  Transmission  System LP, a
pipeline  that  transports  Canadian  gas supply to markets in the  Northeastern
United States; a 50% interest in the Premier  Transmission  Pipeline and a 24.5%
interest in Phoenix  Natural Gas, both in Northern  Ireland;  and investments in
certain  midstream  natural gas assets in Western Canada through KeySpan Canada.
With the  exception  of our gas  exploration  and  production  subsidiaries  and
KeySpan  Canada,  which are  consolidated  in our  financial  statements,  these
subsidiaries  are accounted  for under the equity  method.  Accordingly,  equity
income from these  investments is reflected in Other Income and  (Deductions) in
the Consolidated Statement of Income.

The  accounting  policies  of the  segments  are the same as those  used for the
preparation of the Consolidated Financial Statements. Our segments are strategic
business units that are managed separately because of their different  operating
and regulatory environments.  Operating results of our segments are evaluated by
management on an earnings before interest and taxes ("EBIT") basis. To reflect a
complete picture of the electric  operations,  we reclassified,  for all periods
presented,  KeySpan  Energy  Supply  from the  Energy  Services  segment  to the
Electric Services segment.  This subsidiary  provides  commodity  management and
procurement  services for fuel supply and management of energy sales,  primarily
for and from the  Ravenswood  facility.  Due to the July  2002  sale of  Midland
Enterprises LLC, an inland marine barge business, this subsidiary is reported as
discontinued  operations for all periods  presented.  (See Note 9  "Discontinued
Operations" for more information on the sale of Midland).

The reportable  segment  information  below is shown excluding the operations of
Midland:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                               Gas
                                                                           Exploration
                                    Gas           Electric       Energy        and           Other
(In Thousands of Dollars)       Distribution      Services      Services    Production    Investments    Eliminations   Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
<S>                              <C>             <C>          <C>         <C>            <C>             <C>            <C>
Unaffiliated revenue              3,163,761       1,421,043     938,761      357,451        89,650               -        5,970,666
Intersegment revenue                      -             100           -            -         1,128          (1,228)               -
Depreciation, depletion and
  amortization                      237,186          61,377       9,522      176,925        14,573          15,030          514,613
Income from equity investments            -               -           -            -        13,992             104           14,096
Interest income                       2,020          1,834        1,248            -           238          (3,768)           1,572
Earnings before interest and
  income taxes                      524,311         309,663     (10,377)      95,494        32,771         (27,614)         924,248
Interest charges                    215,140          57,589      19,386        7,303         6,858          (4,772)         301,504
Total assets                      7,452,583       1,739,928     497,269    1,187,425       974,409         762,692       12,614,306
Equity method investments                 -               -           -            -       130,815               -          130,815
Construction expenditures           407,679         371,885      14,316      275,524        48,962          15,511        1,133,877
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Eliminating  items  include  intercompany   interest  income  and  expense,  the
elimination  of certain  intercompany  accounts,  as well as  activities  of our
corporate and administrative subsidiaries.

Electric  Services revenues from LIPA and the NYISO of $1.4 billion for the year
ended  December  31,  2002,  represents  approximately  24% of our  consolidated
revenues during that period.



                                       102
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                                 Gas
                                                                             Exploration
                                      Gas          Electric      Energy          and            Other
(In Thousands of Dollars)         Distribution     Services     Services     Production      Investments  Eliminations  Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2001
<S>                                 <C>           <C>          <C>            <C>            <C>          <C>            <C>
Unaffiliated revenue                 3,613,551     1,421,079    1,100,167      400,031         98,287            -         6,633,115
Intersegment revenue                         -           100            -            -              -         (100)                -
Depreciation, depletion and
  amortization                         253,523        52,284       33,636      184,717         15,737       19,241           559,138
Income from equity investments               -             -            -            -         13,129            -            13,129
Interest income                          3,879           433        3,185            -            334          495             8,326
Earnings before interest and
  income taxes                         492,362       283,533     (143,492)     119,933         21,544       33,975           807,855
Interest charges                       219,307        46,842       21,106        2,993          9,772       53,450           353,470
Total assets                         6,994,140     1,677,710      550,891      951,135        797,294      818,436        11,789,606
Equity method investments                    -             -            -            -        107,069            -           107,069
Construction expenditures              384,323       211,816       17,134      385,463         52,513        8,510         1,059,759
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

Electric  Services revenues from LIPA and the NYISO of $1.4 billion for the year
ended  December  31,  2001  represents  approximately  21% of  our  consolidated
revenues during that period.


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                                Gas
                                                                            Exploration
                                     Gas           Electric       Energy        and          Other
(In Thousands of Dollars)        Distribution      Services      Services    Production   Investments   Eliminations    Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2000
<S>                              <C>             <C>           <C>           <C>           <C>            <C>            <C>
Unaffiliated revenue               2,555,785       1,444,711     770,110       274,209       35,258            629         5,080,702
Intersegment revenue                       -           1,175           -             -            -         (1,175)                -
Depreciation, depletion and
  amortization                       143,335          49,278      10,347        95,364        6,586         26,012           330,922
Income from equity investments             -               -           -             -       20,010              -            20,010
Interest income                        3,951           2,180           -             -        6,134             62            12,327
Earnings before interest and
  income taxes                       367,226         310,823      14,630       111,672       20,014       (103,039)          721,326
Interest charges                     111,176          24,254         125        11,360        7,636         46,763           201,314
Total assets                       7,286,138       1,871,323     755,506       830,170      683,399       (119,071)       11,307,465
Equity method investments                  -               -           -             -      109,751          3,387           113,138
Construction expenditures            274,941          69,921      17,362       243,799       26,388            624           633,035
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

Electric Services revenues from LIPA,  Consolidated Edison and the NYISO of $1.4
billion for the year ended December 31, 2000 represents approximately 28% of our
consolidated revenues during that period.


                                       103
<PAGE>

Note 3. Income Tax

We file a  consolidated  federal  income tax  return.  A tax  sharing  agreement
between our holding company and its subsidiaries  provides for the allocation of
a realized tax liability or benefit based upon separate return  contributions of
each subsidiary to the  consolidated  taxable income or loss in the consolidated
income tax returns.  The  subsidiaries  record  income tax payable or receivable
from KeySpan resulting from the inclusion of their taxable income or loss in the
consolidated return.

Income tax expense is  reflected  as follows in the  Consolidated  Statement  of
Income:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                                 Year Ended December 31,
(In Thousands of Dollars)                               2002              2001              2000
---------------------------------------------------------------------------------------------------
<S>                                                   <C>               <C>               <C>
Current income tax                                    $(48,487)         $101,738          $170,809
Deferred income tax                                    273,881           108,955            46,453
---------------------------------------------------------------------------------------------------
Total income tax                                      $225,394          $210,693          $217,262
---------------------------------------------------------------------------------------------------
</TABLE>

The  components  of  deferred  tax assets  and  (liabilities)  reflected  in the
Consolidated Balance Sheet are as follows:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
                                                                         December 31,
(In Thousands of Dollars)                                         2002                  2001
-------------------------------------------------------------------------------------------------
<S>                                                             <C>                    <C>
Reserves not currently deductible                              $   38,275             $   55,372
Benefits of tax loss carry forwards                               (13,997)                 6,346
Property related differences                                     (818,116)              (498,726)
Regulatory tax asset                                              (18,690)               (22,588)
Property taxes                                                    (52,339)               (61,126)
Discontinued operations                                                 -                (74,936)
Other items - net                                                 (12,146)                (2,414)
-------------------------------------------------------------------------------------------------
Net deferred tax liability                                     $ (877,013)            $ (598,072)
-------------------------------------------------------------------------------------------------
</TABLE>

During the year ended December 31, 2002, an adjustment to deferred  income taxes
of $177.7  million  was  recorded  to reflect a decrease in the tax basis of the
assets acquired at the time of the  KeySpan/LILCO  combination.  This adjustment
resulted  from a revised  valuation  study and the  preparation  of amended  tax
returns.  Concurrent with this deferred tax adjustment,  KeySpan reduced current
income taxes payable by $183.2  million,  resulting in a net $5.5 million income
tax benefit.  Currently,  the Internal Revenue Service is auditing KeySpan's tax
returns  pertaining to the  KeySpan/LILCO  combination,  as well as other return
years. At this time, we cannot predict the outcome of the ongoing audit.




                                       104

<PAGE>

The following is a reconciliation between the effective tax rate and the federal
income tax rate of 35%:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
                                                                                         Year Ended December 31,
(In Thousands of Dollars)                                                    2002                  2001                 2000
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                  <C>                   <C>
Computed at the statutory rate                                            $  217,960           $  159,035            $  182,004
Adjustments related to:
  Tax credits                                                                 (1,026)              (1,100)               (1,181)
  Removal costs                                                               (4,787)              (1,470)               (2,788)
  Accrual to return adjustment                                                (9,539)               2,354                  (508)
  Goodwill amortization                                                            -               21,126                 4,123
  Minority interest in Houston Exploration                                     9,490               13,862                 8,768
  State income tax                                                            30,370               26,418                30,384
  Other items - net                                                          (17,074)              (9,532)               (3,540)
--------------------------------------------------------------------------------------------------------------------------------
Total income tax                                                          $  225,394           $  210,693            $  217,262
--------------------------------------------------------------------------------------------------------------------------------
Effective income tax (1)                                                         36%                  46%                   42%
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Reflects both federal as well as state income taxes.

Note 4. Postretirement Benefits

Pension Plans: The following information represents the consolidated results for
our noncontributory  defined benefit pension plans which cover substantially all
employees. Benefits are based on years of service and compensation.  Funding for
pensions is in  accordance  with  requirements  of federal law and  regulations.
KEDLI is subject to certain  deferral  accounting  requirements  mandated by the
NYPSC for pension costs and other postretirement benefit costs.

Boston Gas  Company is also  subject to  deferral  accounting  requirements,  as
previously  ordered  by the DTE,  for other  postretirement  benefit  costs.  In
addition,  by DTE approval dated January 28, 2003, Boston Gas Company will defer
for the year  2003,  and  record  as  either a  regulatory  asset or  regulatory
liability,  the difference between the level of pension expense that is included
in rates charged to gas customers and the actuarial determined amounts.

Information  pertaining to  discontinued  operations has been excluded from this
presentation.

The calculation of net periodic pension cost is as follows:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                                                                              Year Ended December 31,
(In Thousands of Dollars)                                                          2002                 2001                2000
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>                 <C>                 <C>
Service cost, benefits earned during the period                               $    42,423          $    41,162        $    35,541
Interest cost on projected benefit obligation                                     132,424              128,481            109,231
Expected return on plan assets                                                   (157,958)            (180,757)          (166,744)
Special termination charge (1)                                                          -                    -             45,838
Settlement Gain (2)                                                                     -                    -            (20,196)
Net amortization and deferral                                                      (4,247)             (39,772)           (54,881)
----------------------------------------------------------------------------------------------------------------------------------
Total pension (benefit) cost                                                  $    12,642          $   (50,886)       $   (51,211)
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) See discussion of early retirement program at end of note.
(2) See discussion of pension plan settlement.

Pension cost includes expense and income for KEDNE since November 8, 2000.


                                       105
<PAGE>

The following table sets forth the pension plans' funded status at December 31,
2002 and December 31, 2001. Plan assets are principally common stock and fixed
income securities.
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                                                                                      Year Ended December 31,
(In Thousands of Dollars)                                                                           2002                    2001
----------------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
 <S>                                                                                           <C>                     <C>
  Benefit obligation at beginning of period                                                   $ (1,915,154)          $  (1,914,885)
  Service cost                                                                                     (42,423)                (41,162)
  Interest cost                                                                                   (132,424)               (128,481)
  Amendments                                                                                        (2,932)                 (8,679)
  Actuarial gain (loss)                                                                           (103,988)                 61,718
  Benefits paid                                                                                    116,728                 116,335
----------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                                                             (2,080,193)             (1,915,154)
----------------------------------------------------------------------------------------------------------------------------------
Change in plan assets:
  Fair value of plan assets at beginning of period                                               1,899,256               2,170,093
  Actual return on plan assets                                                                    (347,270)               (197,632)
  Employer contribution                                                                            109,260                  43,130
  Benefits paid                                                                                   (116,728)               (116,335)
----------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                                                       1,544,518               1,899,256
----------------------------------------------------------------------------------------------------------------------------------
  Funded status                                                                                   (535,675)                (15,898)
  Unrecognized net loss from past experience different
  from that assumed and from changes in assumptions                                                627,199                   8,207
  Unrecognized prior service cost                                                                   71,126                  84,036
  Unrecognized transition obligation                                                                   237                   1,212
----------------------------------------------------------------------------------------------------------------------------------
Net prepaid pension cost reflected on
consolidated balance sheet                                                                    $    162,887           $      77,557
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                                                                                          Year Ended December 31,
                                                                                2002                2001               2000
------------------------------------------------------------------------------------------------------------------------------
Assumptions:
  <S>                                                                         <C>                 <C>                 <C>
  Obligation discount                                                           6.75%               7.00%               7.00%
  Asset return                                                                  8.50%               8.50%               8.50%
  Average annual increase in compensation                                       4.00%               4.00%               5.00%
------------------------------------------------------------------------------------------------------------------------------
</TABLE>

Pension Plan  Settlement:  In 2000, we settled certain  participating  contracts
covering  retiree  pension  plans  with  MetLife.  As  required  under  SFAS  88
"Employers'  Accounting for  Settlements  and  Curtailments  of Defined  Benefit
Pension  Plans  and for  Termination  Benefits",  a gain of  $20.2  million  was
recognized as part of our pension cost for the year ended December 31, 2000.

Unfunded  Pension  Obligation:   At  December  31,  2001,   accumulated  benefit
obligations  were  in  excess  of  pension  assets.  As  prescribed  by  SFAS 87
"Employers'  Accounting for Pensions",  we were required to record an additional
$68.9  million  minimum  liability  for this  unfunded  pension  obligation.  At
December 31, 2002, the accumulated  benefit  obligations were re-measured  which


                                       106
<PAGE>

resulted in a revised minimum  liability of $286.3  million.  As permitted under
current  accounting  guidelines,  this accrual can be offset by a  corresponding
debit to a long-term  asset up to the amount of accumulated  unrecognized  prior
service  costs.  Any remaining  amount is to be recorded in Other  Comprehensive
Income.

Therefore,  at year-end,  we have recorded a long-term asset in Deferred Charges
Other of $61.5 million. We also recorded a $118.6 million contractual receivable
in Deferred Charges Other,  representing the amount that would be recovered from
LIPA in accordance  with our service  agreements if the  underlying  assumptions
giving rise to this  minimum  liability  were  realized  and recorded as pension
expense.  The  remaining  charge to equity of $106.2  million,  or $69.0 million
after-tax,  has  been  recorded  as a debit to Other  Comprehensive  Income.  At
December  31,  2002  the  projected  benefit  obligation,   accumulated  benefit
obligation and value of assets for plans with accumulated benefit obligations in
excess of plan  assets were $1.1  billion,  $948.0  million and $621.0  million,
respectively.  At the  end of each  year,  we will  re-measure  the  accumulated
benefit  obligations and pension assets, and adjust the accrual and deferrals as
appropriate.

Other  Postretirement   Benefits:   The  following  information  represents  the
consolidated  results for our  noncontributory  defined  benefit plans  covering
certain health care and life insurance benefits for retired  employees.  We have
been funding a portion of future benefits over  employees'  active service lives
through   Voluntary   Employee   Beneficiary    Association   ("VEBA")   trusts.
Contributions  to  VEBA  trusts  are  tax  deductible,  subject  to  limitations
contained in the Internal Revenue Code.

Net  periodic   other   postretirement   benefit  cost  included  the  following
components:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
                                                                      Year Ended December 31,
(In Thousands of Dollars)                                         2002          2001         2000
----------------------------------------------------------------------------------------------------
<S>                                                             <C>          <C>           <C>
Service cost, benefits earned during the period                  $16,566      $20,339       $14,771
Interest cost on accumulated
   postretirement benefit obligation                              65,486       64,649        47,412
Expected return on plan assets                                   (36,839)     (42,822)      (42,890)
Special termination charge (1)                                         -            -         5,590
Net amortization and deferral                                     17,527       11,664        (9,290)
----------------------------------------------------------------------------------------------------
Other postretirement benefit cost                                $62,740      $53,830       $15,593
----------------------------------------------------------------------------------------------------
</TABLE>
(1)  See  discussion  of  early  retirement   program  at  end  of  note.
Other postretirement benefit costs include expense and income for KEDNE since
November 8, 2000.



                                       107
<PAGE>

The following table sets forth the plans' funded status at December 31, 2002 and
December 31, 2001. Plan assets are principally common stock and fixed income
securities.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------
                                                                                        Year Ended December 31,
(In Thousands of Dollars)                                                               2002               2001
------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
<S>                                                                                <C>                 <C>
  Benefit obligation at beginning of period                                         $ (969,692)        $ (873,421)
  Service cost                                                                         (16,566)           (20,339)
  Interest cost                                                                        (65,486)           (64,649)
  Plan participants' contributions                                                      (1,587)            (1,439)
  Amendments                                                                            57,984                 52
  Actuarial (loss)                                                                    (115,563)           (57,670)
  Benefits paid                                                                         53,966             47,774
------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                                                 (1,056,944)          (969,692)
------------------------------------------------------------------------------------------------------------------
Change in plan  assets:
  Fair value of plan assets at beginning of period                                     476,146            554,866
  Actual return on plan assets                                                         (82,950)           (39,703)
  Employer contribution                                                                 20,349              7,318
  Plan participants' contributions                                                       1,587              1,439
  Benefits paid                                                                        (53,966)           (47,774)
------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                                             361,166            476,146
------------------------------------------------------------------------------------------------------------------
  Funded status                                                                       (695,778)          (493,546)
  Unrecognized net loss from past experience different from
  that assumed and from change in assumptions                                          464,269            251,198
  Unrecognized prior service cost                                                      (60,104)            (8,392)
------------------------------------------------------------------------------------------------------------------
Accrued benefit cost reflected on consolidated balance sheet                        $ (291,613)        $ (250,740)
------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
                                                                         Year Ended December 31,
                                                                   2002           2001           2000
-------------------------------------------------------------------------------------------------------
<S>                                                               <C>            <C>            <C>
Assumptions:
  Obligation discount                                              6.75%          7.00%          7.00%
  Asset return                                                     8.50%          8.50%          8.50%
  Average annual increase in compensation                          4.00%          4.00%          5.00%
-------------------------------------------------------------------------------------------------------
</TABLE>

The measurement of plan  liabilities  also assumes a health care cost trend rate
of 9% grading  down to 5% in 2009 and  thereafter.  A 1%  increase in the health
care cost  trend  rate  would  have the  effect of  increasing  the  accumulated
postretirement  benefit obligation as of December 31, 2002 by $118.4 million and
the net  periodic  health care  expense by $11.0  million.  A 1% decrease in the
health care cost trend rate would have the effect of decreasing the  accumulated
postretirement  benefit obligation as of December 31, 2002 by $104.6 million and
the net periodic health care expense by $9.4 million.


                                       108
<PAGE>

At December 31, 2002,  KeySpan had a  contractual  receivable  from LIPA of $238
million  representing the postretirement  benefits  associated with the electric
business unit employees  recorded in Deferred  Charges Other in the Consolidated
Balance  Sheet.   LIPA  has  been  reimbursing  us  for  costs  related  to  the
postretirement  benefits of the electric  business unit  employees in accordance
with the LIPA Agreements.

Early  Retirement  Program:  In December 2000, we completed an early  retirement
program for certain management and union employees.  Included in the pension and
other  postretirement  benefits expense for the year ended December 31, 2000 are
charges of $45.8  million and $5.6  million,  respectively  related to the early
retirement program.

Defined  Contribution  Plan:  KeySpan also offers both its union and  management
employees a defined  contribution  plan. Both the KeySpan Energy 401(k) Plan for
Management  Employees and the KeySpan Energy 401(k) Plan for Union Employees are
available to all eligible employees.  These Plans are defined contribution plans
subject  to  Title I of the  Employee  Retirement  Income  Security  Act of 1974
("ERISA").  All eligible  employees  contributing  to the Plan receive a certain
employer   matching   contribution   based  on  a  percentage  of  the  employee
contribution,  as  well as a 10%  discount  on the  KeySpan  Common  Stock  Fund
anywhere from three to twelve months after their date of hire depending upon the
Plan. The matching  contributions  are in KeySpan's  common stock. The match and
discount  amounts may be transferred  out of common stock  immediately.  For the
years ended  December 31, 2002,  2001 and 2000,  we recorded an expense equal to
$11.2 million, $11.0 million and $6.7 million respectively.

Note 5. Capital Stock

Common Stock:  Currently we have 450,000,000  shares of authorized common stock.
In 1998,  we  initiated  a program to  repurchase  a portion of our  outstanding
common  stock on the open  market.  At December  31,  2002,  we had 16.4 million
shares,  or  approximately  $475  million  of  Treasury  Stock  outstanding.  We
completed this repurchase plan in 1999 and now utilize Treasury Stock to satisfy
our common stock plans.  During 2002, we issued 3 million shares out of treasury
for the  dividend  reinvestment  feature of our Investor  Program,  the Employee
Stock Discount Purchase Plan and the 401(k) Plan.

On January 17,  2003,  KeySpan  sold 13.9  million  shares of common  stock in a
public offering that generated net proceeds of approximately  $473 million.  All
shares were  offered by KeySpan  pursuant to the  effective  shelf  registration
statement  filed  with the SEC.  Net  proceeds  from the  equity  sale were used
initially to pay down commercial paper.

Preferred Stock: We have the authority to issue 100,000,000  shares of preferred
stock with the following classifications:  16,000,000 shares of preferred stock,
par value $25 per share; 1,000,000 shares of preferred stock, par value $100 per
share; and 83,000,000 shares of preferred stock, par value $.01 per share.


                                       109
<PAGE>

At December 31, 2002 we had 553,000 shares  outstanding of 7.07% Preferred Stock
Series B par value $100;  197,000 shares  outstanding of 7.17%  Preferred  Stock
Series C par value $100;  and 88,486 shares  outstanding  of 6% Preferred  Stock
Series A par value $100, in the aggregate totaling $83.8 million.

Boston Gas Company has 562,700 shares of 6.421%  non-voting  preferred stock par
value $25 per share  outstanding  at December 31, 2002.  This issue of preferred
stock has a 5% annual  sinking  fund  requirement  and $1.5  million was paid on
September 1, 2002 to satisfy this requirement.  We have the option of increasing
the sinking fund payment up to 10% per year. This issue is callable beginning in
2003 and is reflected in Minority Interest on the Consolidated Balance Sheet.

Note 6. Long-Term Debt

Gas Facilities  Revenue Bonds:  KEDNY can issue tax-exempt bonds through the New
York State Energy Research and Development Authority.  Whenever bonds are issued
for  new  gas  facilities   projects,   proceeds  are  deposited  in  trust  and
subsequently withdrawn to finance qualified  expenditures.  There are no sinking
fund  requirements  on any of our Gas Facilities  Revenue Bonds. At December 31,
2002, KEDNY had $648.5 million of Gas Facilities Revenue Bonds outstanding.  The
interest  rate on the variable  rate series due December 1, 2020 is reset weekly
and ranged from 1.00% to 1.68% through December 31, 2002, at which time the rate
was 1.28%.

Authority Financing Notes: One of our electric generation subsidiaries can issue
tax-exempt  bonds  through the New York State Energy  Research  and  Development
Authority. At December 31, 2002, $41.1 million of Authority Financing Notes 1999
Series A Pollution  Control Revenue Bonds due October 1, 2028 were  outstanding.
The  interest  rate on these notes is reset based on an auction  procedure.  The
interest rate during the year ranged from 1.00% to 1.68%,  through  December 31,
2002, at which time the rate was 1.20%.

We also have  outstanding  $24.9  million  variable  rate 1997 Series A Electric
Facilities  Revenue Bonds due December 1, 2027. The interest rate on these bonds
is reset weekly and ranged from .95% to 1.90% through December 31, 2002 at which
time the rate was 1.60%.

Promissory Notes: In connection with the KeySpan/LILCO transaction,  KeySpan and
certain of its subsidiaries  issued  promissory notes to LIPA to support certain
debt obligations  assumed by LIPA. The remaining  principal amount of promissory
notes issued to LIPA was  approximately  $600  million at December 31, 2002.  In
February 2003,  KeySpan  notified LIPA of its intention to redeem  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. It is anticipated that such redemption will take place before the
end of the first  quarter of 2003.  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.


                                       110
<PAGE>

Notes Payable:  KEDLI had $125 million of Medium-Term Notes at 6.90% due January
15,  2008,  and $400 million of 7.875%  Medium-Term  Notes due February 1, 2010,
outstanding at December 31, 2002 each of which is guaranteed by KeySpan.

Further,  KeySpan had $2.36 billion of Medium-Term Notes outstanding at December
31,  2002 of  which  $1.65  billion  of  these  notes  are  associated  with the
acquisition  of Eastern  and ENI.  These  notes were  issued in three  series as
follows: $700 million, 7.25% Notes due 2005; $700 million, 7.625% Notes due 2010
and $250 million,  8.00% Notes due 2030. The remaining Medium-Term Notes of $710
million have interest rates ranging from 6.15% to 9.75% and mature in 2005-2025.

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

These  securities  are  currently not  considered  convertible  instruments  for
purposes of applying SFAS 128 "Earnings Per Share" calculations, unless or until
such  time  as the  market  value  of  our  common  stock  reaches  a  threshold
appreciation  price ($42.36 per share) that is higher than the current per share
market value. Interest payments do, however,  reduce net income and earnings per
share.

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

At December 31, 2001,  KeySpan had  authorization  under PUHCA to issue up to $1
billion  of  securities  and had an  effective  $1  billion  shelf  registration
statement on file with the SEC, with $500 million  available  for  issuance.  In
February  2002,  we  updated  the  shelf  registration  for the  issuance  of an
additional  $1.2 billion of  securities,  thereby  giving KeySpan the ability to


                                       111
<PAGE>

issue up to $1.7 billion of debt,  equity or various  forms of preferred  stock.
The  issuance  of the MEDS  Equity  Units  utilized  $920  million of  KeySpan's
financing  authority under both the shelf  registration  and the PUHCA financing
authority.  Both the $460 million  six-year  note and the $460  million  forward
equity contract are considered  current issuances under these  arrangements.  On
December 6, 2002, the SEC issued an order increasing the available authorization
amount of financing  under PUHCA to an aggregate of $780 million.  Following the
recent  common stock  offering  mentioned  in Note 5 "Capital  Stock" and shares
expected to be issued for employee benefit and dividend  reinvestment  plans, we
have  approximately  $40 million  available  for the issuance of new  securities
under our current PUHCA  authorization.  However,  the issuance of securities in
connection with the redemption of existing securities  (including the promissory
notes  discussed   previously)  is  permitted  under  our  PUHCA   authorization
notwithstanding  the foregoing  limit. We intend to seek  authorization to issue
additional securities in the near term.

At December 31, 2002, Houston Exploration had outstanding $100 million of 8.625%
Senior  Subordinated  Notes  due  2008.  These  notes  were  issued in a private
placement  in  March  1998  and are  subordinate  to  borrowings  under  Houston
Exploration's  line of  credit.  These  notes are  redeemable  at the  option of
Houston Exploration after January 1, 2003.

First Mortgage  Bonds:  Colonial Gas Company,  Essex Gas Company,  ENI and their
respective  subsidiaries,  have  issued  and  outstanding  approximately  $163.6
million of first  mortgage  bonds.  These bonds are secured by KEDNE gas utility
property.  The first mortgage bond indentures  include,  among other provisions,
limitations  on: (i) the issuance of long-term debt; (ii) engaging in additional
lease obligations; and (iii) the payment of dividends from retained earnings.

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

Commercial Paper and Revolving Credit  Agreements:  In 2002, KeySpan renewed its
existing 364-day  revolving credit agreement with a commercial bank syndicate of
16 banks  totaling  $1.3  billion,  a reduction  from the previous  $1.4 billion
facility.  The credit  facility is used to back up the $1.3  billion  commercial
paper program.  The fees for the facility are subject to a  ratings-based  grid,
with an annual fee of .075% on the total amount of the revolving  facility.  The
credit agreement  allows for KeySpan to borrow using several  different types of
loans;  specifically,  Eurodollar loans,  Adjustable Bank Rate ("ABR") loans, or
competitively bid loans.  Eurodollar loans are based on the Eurodollar rate plus
a margin  of 42.5  basis  points  for  loans up to 33% of the  facility,  and an
additional 12.5 basis points for loans over 33% of the total facility. ABR loans
are based on the  greater  of the Prime  Rate,  the base CD rate plus 1%, or the
Federal Funds  Effective Rate plus 0.5%.  Competitive bid loans are based on bid
results  requested by KeySpan from the lenders.  We do not anticipate  borrowing
against this facility;  however,  if the credit rating on our  commercial  paper
program  were to be  downgraded,  it may be  necessary  to borrow on the  credit
facility.


                                       112
<PAGE>

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 and certain  financial
covenants  that  require us to,  among  other  things,  maintain a  consolidated
indebtedness  to  consolidated  capitalization  ratio  of no more  than  66%,  a
decrease from the 68% ratio required under the previous credit facility.

Under  the  terms  of  the  credit   facility,   the  calculation  of  KeySpan's
debt-to-total  capitalization  ratio reflects 80% equity  treatment for the MEDS
Equity Units  issued in May 2002.  Further the $425  million  Ravenswood  master
lease ("Master Lease") is treated as debt. (See Note 7 "Contractual Obligations,
Financial  Guarantees  and  Contingencies"  for a discussion  of the  Ravenswood
Master Lease.) At December 31, 2002,  consolidated  indebtedness,  as calculated
under   the  terms  of  the   credit   facility,   was  64.6%  of   consolidated
capitalization.  As a result of the common stock offering previously  mentioned,
this ratio has been reduced to 59.8%. 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.

The  credit  facility  also  requires  that net cash  proceeds  from the sale of
subsidiaries  be  applied  to  reduce  consolidated  indebtedness.  Further,  an
acceleration of indebtedness of KeySpan or one of its  subsidiaries for borrowed
money in excess of $25 million in the aggregate,  if not annulled within 30 days
after  written  notice,  would create an event of default  under the  Indenture,
dated  as of  November  1,  2000,  between  KeySpan  Corporation  and the  Chase
Manhattan Bank, as Trustee. At December 31, 2002, KeySpan was in compliance with
all covenants.

At December 31,  2002,  we had cash and  temporary  cash  investments  of $170.6
million.  During,  2002,  we repaid $132.8  million of commercial  paper and, at
December 31, 2002,  $915.7  million of  commercial  paper was  outstanding  at a
weighted average annualized interest rate of 1.52%. We had the ability to borrow
up to an  additional  $384.3  million at December 31, 2002 under the  commercial
paper program.

During 2002,  Houston  Exploration  entered into a new revolving credit facility
with a commercial  banking  syndicate  that  replaced the existing  $250 million
revolving credit facility. The new facility provides Houston Exploration with an
initial commitment of $300 million,  which can be increased,  at its option to a
maximum of $350 million with prior approval from the banking syndicate.  The new
credit facility is subject to borrowing base limitations,  initially set at $300
million  and  will be  re-determined  semi-annually.  Up to $25  million  of the
borrowing  base is  available  for the  issuance  of letters of credit.  The new
credit  facility  matures  July 15, 2005,  is unsecured  and ranks senior to all
existing debt.

Under the Houston  Exploration  credit facility,  interest on base rate loans is
payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater
of the  federal  funds  rate  plus  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 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.


                                       113
<PAGE>

Financial  covenants  require Houston  Exploration  to, among other things,  (i)
maintain an interest  coverage ratio of at least 3.00 to 1.00 of earnings before
interest,  taxes and depreciation  ("EBITDA") to cash interest;  (ii) maintain a
total  debt to EBITDA  ratio of not more than 3.50 to 1.00;  and (iii)  hedge no
more than 70% of natural gas production  during any 12-month period. At December
31, 2002, Houston Exploration was in compliance with all financial covenants.

During  2002,  Houston  Exploration  borrowed  $79.0  million  under its  credit
facility  and repaid  $71.0  million.  At December  31,  2002,  $152  million of
borrowings  remained  outstanding at a weighted average annualized interest rate
of 3.42%.  Also, $0.4 million was committed under outstanding  letters of credit
obligations.  At December 31,  2002,  $147.6  million of borrowing  capacity was
available.

KeySpan Canada has two revolving credit  facilities with financial  institutions
in Canada.  Repayments  under these  agreements  totaled  approximately US $26.1
million during 2002. At December 31, 2002,  approximately  US $150.9 million was
outstanding at a weighted  average  annualized  interest rate of 3.23%.  KeySpan
Canada  currently has available  borrowings of  approximately  US $55.8 million.
These revolving  credit  agreements have been extended  through January 2004. An
event of default  would exist  under  these  credit  facilities  if KeySpan,  as
guarantor on the facilities,  falls below investment grade rating or falls below
A3 or A- at a time when its  consolidated  indebtedness  is greater  than 66% of
consolidated  capitalization  or its cash flow to interest  expense is less than
2.25 to  1.00.  At  December  31,  2002,  KeySpan  and  KeySpan  Canada  were in
compliance with all covenants.

Capital Leases:  Our subsidiaries  lease certain  facilities and equipment under
long-term  leases,  which expire on various  dates  through  2022.  The weighted
average interest rate on these obligations was 6.25%.

Debt Maturity:  The following table reflects the maturity  schedule for our debt
repayment requirements,  including capitalized leases and related maturities, at
December 31, 2002:

---------------------------------------------------------------------------
                                      Long-Term      Capital
 (In Thousands of Dollars)               Debt         Leases        Total
---------------------------------------------------------------------------
 Repayments:
     Year 1                         $     10,333   $  1,080    $    11,413
     Year 2                                  333      1,033          1,366
     Year 3                            1,327,333      1,044      1,328,377
     Year 4                              512,333      1,003        513,336
     Year 5                                  333      1,061          1,394
     Thereafter                        3,379,190      8,663      3,387,853
---------------------------------------------------------------------------
                                    $  5,229,855   $ 13,884    $ 5,243,739
---------------------------------------------------------------------------


                                       114
<PAGE>

Note 7. Contractual Obligations, Financial Guarantees and Contingencies

Lease Obligations:  Lease costs included in operation expense were $71.1 million
in 2002  reflecting,  primarily,  the Master Lease and the lease of our Brooklyn
headquarters of $29.1 million and $14.3 million, respectively.  Lease costs also
include  leases  for  other  buildings,  office  equipment,  vehicles  and power
operated  equipment.  Lease costs for the year ended  December 31, 2001 and 2000
were $75.8 million and $69.3  million,  respectively.  The future  minimum lease
payments  under various  leases,  all of which are operating  leases,  are $80.8
million per year over the next five years and $200.9 million,  in the aggregate,
for all years thereafter, including future minimum lease payments for the Master
Lease of $30.8  million per year over the next five years and $61.7  million for
all years thereafter (See discussion below for further information regarding the
Master Lease.)

Variable  Interest Entity:  KeySpan has an arrangement with a variable  interest
entity through which we lease a portion of the Ravenswood facility.  We acquired
the Ravenswood  facility,  in part,  through the variable  interest  entity from
Consolidated Edison on June 18, 1999 for approximately $597 million. In order to
reduce the initial  cash  requirements,  we entered into the Master Lease with a
variable interest,  unaffiliated financing entity that acquired a portion of the
facility, or 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 units or the variable interest entity.

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

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  generally 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.


                                       115
<PAGE>

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

Prospectively,  KeySpan  will have a $425  million  asset that will be amortized
over the economic life of the leased  property.  However,  upon  implementation,
there will be a cumulative catch-up adjustment for a change in accounting policy
as if the asset had been owned from inception,  or June 20, 1999. Therefore,  at
July 1, 2003,  assuming a 35 year economic life,  KeySpan will be deemed to have
owned the asset for  approximately  4 years and it is  anticipated  that we will
record  a $31.6  million  after-tax  charge,  or  $0.20  per  share,  change  in
accounting   principle   on  the   Consolidated   Statement   of  Income.   Upon
implementation  of FIN 46,  therefore,  we  anticipate  recording  an  asset  of
approximately $376 million and debt of $425 million.

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

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

KeySpan is currently exploring various options associated with the Master Lease,
including but not limited to, restructuring the current leasing arrangement.  At
this time, we cannot predict the future structure of the leasing arrangement nor
the impact on our financial position, results of operations or cash flows.

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 December 31, 2002, 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:


                                       116
<PAGE>
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                                                              Amount of      Expiration
Nature of Guarantee (In Thousands of Dollars)                                  Exposure         Dates
-----------------------------------------------------------------------------------------------------------
<S>                                                          <C>             <C>            <C>
Guarantees for Subsidiaries
 Medium-Term Notes - KEDLI                                    (i)            $    525,000     2008-2010
 Master Lease  - Ravenswood                                   (ii)                425,000        2004
 Revolving Credit Agreement - KeySpan Canada                  (iii)               130,000        2004
 Surety Bonds                                                 (iv)                153,900     Revolving
 Commodity Guarantees and Other                               (v)                  65,700        2005
 Letters of Credit                                            (vi)                 64,400        2003
-----------------------------------------------------------------------------------------------------------
Guarantees for Non-Affiliates
 Third Party Line of Credit                                   (vii)                25,000        2004
-----------------------------------------------------------------------------------------------------------
                                                                             $  1,389,000
-----------------------------------------------------------------------------------------------------------
</TABLE>


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

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

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

(iv) KeySpan has purchased  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  obligation
     under contract,  the injured party may demand that the surety make payments
     or provide  services  under the bond.  KeySpan  would then be  obligated to
     reimburse the surety for any expenses or cash outlays it incurs.

(v)  KeySpan has guaranteed  commodity-related  payments for subsidiaries within
     the Energy  Services  segment,  as well as KeySpan  Ravenswood,  LLC. These
     guarantees  are  provided  to third  parties  to  facilitate  physical  and
     financial  transactions  involved in the  purchase of natural  gas, oil and
     other petroleum products for electric production and marketing  activities.
     The guarantees cover actual purchases by these  subsidiaries that are still
     outstanding  as of December  31,  2002.


                                       117
<PAGE>

(vi) KeySpan  has  issued  stand-by  letters  of credit  in the  amount of $64.4
     million to third parties that have extended credit to certain subsidiaries.
     Certain  vendors  require  us  to  post  letters  of  credit  to  guarantee
     subsidiary  performance  under our contracts  and to ensure  payment to our
     subsidiary subcontractors and vendors under those contracts. Certain of our
     vendors also require letters of credit to ensure  reimbursement for amounts
     they are disbursing on behalf of our subsidiaries, such as to beneficiaries
     under our  self-funded  insurance  programs.  Such  letters  of credit  are
     generally issued by a bank or similar financial institution. The letters of
     credit  commit  the  issuer to pay  specified  amounts to the holder of the
     letter of credit if the holder  demonstrates that we have failed to perform
     specified  actions.  If this were to occur,  KeySpan  would be  required to
     reimburse the issuer of the letter of credit.

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 details may have on our  consolidated  results
of operations, financial condition or cash flows.

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

(vii)KeySpan  has agreed to support a line of credit up to $25 million on behalf
     of Hawkeye  Construction  ("Hawkeye"),  a non-affiliated  company.  It also
     assisted Hawkeye in obtaining  performance bonds. The guarantees related to
     their line of credit extend  through  2004. To the extent  Hawkeye does not
     meet  its  obligations,  KeySpan  could be  liable  for the  amount  of the
     outstanding guarantees. At December 31, 2002, the amount guaranteed was $25
     million.

     If Hawkeye fails to perform under a contract or to pay  subcontractors  and
     vendors,  the counter-party  that requested the performance bond may demand
     that the surety make payments or provide  services under the bond.  KeySpan
     would then have to  reimburse  the surety for any  expenses  or outlays the
     surety  incurs.  To date,  we have not had a claim made against  either the
     guarantee  associated  with the line of  credit or the  performance  bonds.
     KeySpan is  presently  engaged in a legal  action with Hawkeye as discussed
     further in "Legal Matters" below.

Fixed Charges Under Firm Contracts:  Our utility subsidiaries and the Ravenswood
facility  have entered  into various  contracts  for gas  delivery,  storage and
supply  services.  The  contracts  have  remaining  terms that cover from one to
thirteen  years.  Certain of these  contracts  require  payment of annual demand
charges in the aggregate amount of approximately  $462.3 million.  We are liable
for these  payments  regardless  of the level of service  we require  from third
parties. Such charges are currently recovered from utility customers through the
gas adjustment clause.


                                       118
<PAGE>

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,
we do not  consider  any of such  proceedings  to be material to our business or
likely to result in a material  adverse  effect on our  results  of  operations,
financial condition or cash flows.

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

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

Furthermore, KeySpan and certain of its officers and directors are defendants in
a number of class action  lawsuits filed in the United States District Court for
the  Eastern  District  of New York  after  the July  17th  announcement.  These
lawsuits allege,  among other things,  violations of Sections 10(b) and 20(a) of
the Securities  Exchange Act of 1934, as amended ("Exchange Act"), in connection
with  disclosures  relating  to or  following  the  acquisition  of the  Roy Kay
companies by KeySpan Services,  Inc., a KeySpan  subsidiary and the announcement
of the  agreement  to acquire  Eastern  and ENI.  Finally,  in October  2001,  a
shareholder's  derivative action was commenced in the same court against certain
officers and directors of KeySpan,  alleging,  among other  things,  breaches of
fiduciary  duty,  violations  of the  New  York  Business  Corporation  Law  and
violations  of  Section  20(a)  of the  Exchange  Act.  In  addition,  a  second
derivative action has been commenced asserting similar allegations.  Each of the
proceedings  seek monetary  damages in an  unspecified  amount.  We have filed a
motion to dismiss the class action lawsuits which is currently  pending.  We are
unable to determine the outcome of these  proceedings  and what effect,  if any,
such outcome will have on our financial condition, results of operations or cash
flows.

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


                                       119
<PAGE>

asbestos in connection  with the  construction  and  maintenance of our electric
generating  facilities.  Certain subsidiaries have also been named as defendants
in proceedings  involving  facilities not owned by KeySpan. At the present time,
KeySpan is unable to determine  the outcome of these  proceedings,  but does not
believe  that such  outcome,  if  adverse,  will have a  material  effect on its
financial condition, results of operations or cash flows.

KeySpan, through its subsidiary, formerly known as Roy Kay, Inc., has terminated
the  employment  of the former  owners of the Roy Kay  companies and commenced a
proceeding in the Chancery Division of the Superior Court,  Monmouth County, New
Jersey (Docket No. Mon. C. 95-01) as a result of the alleged  fraudulent acts of
the  former  owners,  both  before  and  after  the  acquisition  of the Roy Kay
companies in January  2000.  KeySpan  believes the former  owners  misstated the
financial   statements  of  the  Roy  Kay   companies  and  certain   underlying
work-in-progress schedules. KeySpan is seeking damages in excess of $76 million,
as well as a judicial  determination  that  KeySpan is not  required  to pay the
former  owners  any  further  amounts  under  the  terms of the  stock  purchase
agreement  entered  into  in  connection  with  the  acquisition  of the Roy Kay
companies.  The causes of action include breach of contract and fiduciary  duty,
fraud,  and violation of the New Jersey  Securities Laws. The former owners have
filed counterclaims against KeySpan and certain of its subsidiaries,  as well as
certain of their  respective  officers,  to recover  damages  they claim to have
incurred as a result of, among other things,  their alleged improper termination
and the  alleged  fraud  on the part of  KeySpan  in  failing  to  disclose  the
limitations imposed upon the Roy Kay companies,  with respect to the performance
of certain  services under PUHCA. The fraud claims asserted by the former owners
include claims under the New Jersey Uniform Securities Law and RICO statutes. 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.

Environmental Matters

Air: With respect to NOx emissions reduction requirements for our existing power
plants,  we are  required  to be in  compliance  with the  Phase  III  reduction
requirements of the Ozone Transportation  Commission  memorandum by May 1, 2003,
and we  fully  expect  to  achieve  such  emission  reductions  on time and in a
cost-effective   manner.   Our  expenditures  to  address   emission   reduction
requirements  through  the year 2003 are  expected to be between $10 million and
$15 million.

Water:  Additional  capital  expenditures  associated  with the  renewal  of the
surface  water  discharge  permits  for our power  plants may be required by the
Department  of  Environmental   Conservation   ("DEC").   Until  our  monitoring
obligations  are completed and changes to the  Environmental  Protection  Agency
regulations  under Section 316 of the Clean Water Act are promulgated,  the need
for and the cost of equipment upgrades cannot be determined.


                                       120
<PAGE>

Land: Manufactured Gas Plants and Related Facilities

New York Sites:  Within the State of New York we have identified 28 manufactured
gas plant ("MGP") sites and related facilities, which were historically owned or
operated by KeySpan subsidiaries or such companies'  predecessors.  These former
sites, some of which are no longer owned by us, have been identified to both the
DEC for inclusion on appropriate site inventories and listing with the NYPSC.

We have identified 18 sites  associated  with the historic  operations of KEDNY.
Administrative  Orders on Consent ("ACO") or Voluntary  Cleanup  Agreements have
been  executed  with  the  DEC to  address  the  investigation  and  remediation
activities  associated  with  three  of these  sites.  In  2001,  KEDNY  filed a
complaint  for the  recovery  of its  remediation  costs in the New  York  State
Supreme  Court  against  the various  insurance  companies  that issued  general
comprehensive liability policies to KEDNY. The outcome of this proceeding cannot
yet be determined.  We presently  estimate the remaining  environmental  cleanup
activities of these sites will be $81.1  million,  which amount has been accrued
by  us.  Expenditures  incurred  to  date  by us  with  respect  to  MGP-related
activities total $26.8 million.

We have identified nine sites associated with the historic  operations of KEDLI,
six of which are the subject of two separate  ACOs,  which we executed  with the
DEC in 1999. Field investigations and, in some cases, interim remedial measures,
are underway or scheduled to occur at each of these sites under the  supervision
of the DEC and the New York State  Department of Health.  Pursuant to a separate
ACO also entered into in 1999, we have performed preliminary site assessments at
five other sites,  which were formerly  owned by KEDLI.  For one of these sites,
the DEC has advised us that no further action is required.  At another site, the
DEC has  indicated  that a  remedial  investigation  will be  required.  For the
remaining three sites, KeySpan awaits the DEC's comments.

In January  1998,  KEDLI filed a complaint  for the recovery of its  remediation
costs  in the New  York  State  Supreme  Court  against  the  various  insurance
companies that issued general  comprehensive  liability  policies to KEDLI.  The
outcome of this proceeding cannot yet be determined.  We presently  estimate the
remaining environmental cleanup activities of these sites will be $61.1 million,
which  amount has been accrued by us.  Expenditures  incurred to date by us with
respect to KEDLI MGP-related activities total $22.3 million.

We presently estimate the remaining cost of our New York/Long Island MGP-related
environmental  cleanup activities will be $142.2 million,  which amount has been
accrued  by us as a  reasonable  estimate  of  probable  cost for  known  sites.
Expenditures incurred to date by us with respect to these MGP-related activities
total $49.1 million.

With respect to remediation  costs,  the KEDNY rate plan  provides,  among other
things, that if the total cost of investigation and remediation varies from that
which  is  specifically   estimated  for  a  site  under  investigation   and/or
remediation,  then KEDNY will retain or absorb up to 10% of the  variation.  The
KEDLI rate plan also provides for the recovery of investigation  and remediation
costs but with no consideration of the difference  between  estimated and actual
costs.  Under  prior  rate  orders,  KEDNY has  offset  certain  amounts  due to
ratepayers against its estimated  environmental  cleanup costs for MGP sites. At
December 31, 2002, we have  reflected a regulatory  asset of $123.7  million for
our New York/Long Island MGP sites.


                                       121
<PAGE>

We are  also  responsible  for  environmental  obligations  associated  with the
Ravenswood  facility,  purchased  from  Consolidated  Edison in 1999,  including
remediation  activities associated with its historic operations and those of the
MGP facilities  that formerly  operated at the site. We are not  responsible for
liabilities  arising from disposal of waste at off-site  locations  prior to the
acquisition  closing and any monetary fines arising from  Consolidated  Edison's
pre-closing conduct. We presently estimate the remaining  environmental clean up
activities for this site will be $3.6 million,  which amount has been accrued by
us. Expenditures incurred to date total $1.4 million.

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

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

In March  1999,  Boston Gas Company and a  subsidiary  of National  Grid filed a
complaint for the recovery of remediation  costs in the  Massachusetts  Superior
Court against  various  insurance  companies that issued  comprehensive  general
liability  policies to National Grid and its predecessors with respect to, among
other  things,  the 11 sites for which  Boston Gas  Company has agreed to make a
limited  contribution.  The outcome of this  proceeding  cannot be determined at
this time.

We  presently  estimate  the  remaining  cost  of  these   Massachusetts   KEDNE
MGP-related environmental cleanup activities will be $32.4 million, which amount
has been  accrued by us as a  reasonable  estimate  of  probable  cost for known
sites.  Expenditures  incurred  since  November  8, 2000 with  respect  to these
MGP-related activities total $10.7 million.

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.  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.


                                       122
<PAGE>

With  respect to the  Laconia and Nashua  sites,  EnergyNorth  has entered  into
separate cost sharing agreements with Public Service of New Hampshire  ("PSNH").
Under the  agreements  PSNH is  obligated to  indemnify  EnergyNorth  for future
remediation  costs, with limited  exceptions,  at the Laconia site and PSNH will
pay  EnergyNorth  up to $4.8 million toward the costs of the  investigation  and
remediation at the Nashua site.  EnergyNorth  also has entered into an agreement
with  the  United  States  Environmental   Protection  Agency  ("EPA")  for  the
contamination  from the Nashua site that was allegedly  commingled with asbestos
at the so-called Nashua River Asbestos Site, adjacent to the Nashua MGP site.

EnergyNorth  has filed  suit in both the New  Hampshire  Superior  Court and the
United States  District  Court for the District of New Hampshire for recovery of
its  remediation  costs  against the  various  insurance  companies  that issued
comprehensive  general  liability  and excess  liability  insurance  policies to
EnergyNorth and its predecessors. Settlements have been reached with some of the
carriers and one carrier was dismissed  from a Superior  Court action on summary
judgment.  The outcome of the remaining  proceedings  cannot yet be  determined.
EnergyNorth  has also filed a contribution  action in the United States District
Court for the  District  of New  Hampshire  against an entity it alleges  shares
liability for the Manchester MGP study and remediation costs.

We  presently   estimate  the   remaining   cost  of   EnergyNorth   MGP-related
environmental  cleanup  activities will be $14.7 million,  which amount has been
accrued  by us as a  reasonable  estimate  of  probable  cost for  known  sites.
Expenditures  incurred since November 8, 2000, with respect to these MGP-related
activities total $5.3 million.

By rate  orders,  the  DTE  and the  NHPUC  provide  for  the  recovery  of site
investigation and remediation costs and,  accordingly,  at December 31, 2002, we
have reflected a regulatory  asset of $58.7 million for the KEDNE MGP sites.  As
previously mentioned, Colonial Gas Company and Essex Gas Company are not subject
to the  provisions of SFAS 71 and therefore  have recorded no regulatory  asset.
However,  rate plans currently in effect for these subsidiaries  provide for the
recovery of investigation and remediation costs.

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

KeySpan,  Honeywell and Beazer East have entered into a  cost-sharing  agreement
under which each company has agreed to pay  one-third of the costs of compliance
with the consent  order,  while  preserving  any claims it may have  against the
other companies.  The companies have completed  preliminary  remedial  measures,
including  abatement of seepage of materials into the adjacent  tidal river.  In
2002,  Beazer  East  commenced  an action with the U.S.  District  Court for the
Southern  District  of New York  which  seeks a  judicial  determination  on the
allocation of liability for the Everett Facility. The outcome of this proceeding
cannot yet be determined.


                                       123
<PAGE>

KeySpan also is  recovering  certain  legal defense costs and may be entitled to
recover remediation costs from its insurers. We presently estimate the remaining
cost of our  environmental  cleanup  activities for the three  non-utility sites
will be  approximately  $39.2 million,  which amount has been accrued by us as a
reasonable  estimate of probable  costs for known sites.  Expenditures  incurred
since November 8, 2000, with respect to these sites total $4.0 million.

We believe that in the aggregate,  the accrued  liability for  investigation and
remediation  of sites and related  facilities  identified  above are  reasonable
estimates of likely cost within a range of reasonable, foreseeable costs. We may
be required to investigate and, if necessary,  remediate each of these, or other
currently  unknown former sites and related facility sites, the cost of which is
not  presently  determinable  but may be  material  to our  financial  position,
results of  operations  or cash  flows.  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.

Note 8.  Hedging, Derivative Financial Instruments and Fair Values

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

Houston Exploration has utilized collars,  as well as  over-the-counter  ("OTC")
swaps to hedge the cash flow  variability  associated with forecasted sales of a
portion  of its  natural  gas  production.  As of  December  31,  2002,  Houston
Exploration has hedged  approximately 67% and 20% of its estimated 2003 and 2004
production, respectively. Further, Houston Exploration may enter into additional
derivative  positions for 2003 and 2004.  Houston  Exploration used standard New
York Mercantile  Exchange  ("NYMEX") futures prices and published  volatility in
its Black-Scholes calculation to value its outstanding derivatives.  The maximum
length  of time  over  which  Houston  Exploration  has  hedged  such  cash flow
variability is through December 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 $34.9 million, or $22.7 million after-tax.

With respect to price exposure associated with fuel purchases for the Ravenswood
facility,  KeySpan  employs  standard  NYMEX  natural gas futures  contracts and
over-the-counter  financially  settled natural gas basis swaps to hedge the cash
flow  variability of a portion of forecasted  purchases of natural gas.  KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow  variability of a portion of forecasted  purchases of fuel oil that will be


                                       124
<PAGE>

consumed at the  Ravenswood  facility.  The maximum length of time over which we
have hedged cash flow variability  associated with: (i) forecasted  purchases of
natural gas is through December 2003; and (ii) forecasted  purchases of fuel oil
is through April 2004. We used  standard  NYMEX futures  prices to value the gas
futures contracts and industry published oil indices for number 6 grade fuel oil
to value the oil swap contracts.  The estimated  amount of gains associated with
all such derivative  instruments that are reported in Other Comprehensive Income
and that are  expected to be  reclassified  into  earnings  over the next twelve
months is $4.5 million, or $2.9 million after-tax.

Our retail gas and electric marketing subsidiary,  our domestic gas distribution
operations and KeySpan Canada  employed NYMEX natural gas futures  contracts and
natural gas swaps to lock-in a price for expected  future natural gas purchases.
As applicable,  we used standard  NYMEX futures prices and relevant  natural gas
indices to value the  outstanding  contracts.  The  maximum  length of time over
which we have hedged such cash flow  variability  is through  December 2003. The
estimated amount of gains  associated with such derivative  instruments that are
reported in Other Comprehensive  Income and that are expected to be reclassified
into  earnings  over the next twelve  months is $4.9  million,  or $3.2  million
after-tax.

We have also engaged in the use of  cash-settled  swap  instruments to hedge the
cash flow variability  associated with (i) a portion of forecasted peak electric
energy sales from the Ravenswood  facility and (ii) forecasted sales of Unforced
Capacity  ("UCAP") to the NYISO.  The maximum  length of time over which we have
hedged cash flow variability is through March 2004. We used  NYISO-location zone
published  indices as well as  published  NYISO  bidding  prices to value  these
outstanding  derivatives.  The estimated  amount of losses  associated with such
derivative  instruments that are reported in Other Comprehensive Income and that
are expected to be  reclassified  into  earnings  over the next twelve months is
$1.1 million, or $0.7 million after-tax.

KeySpan  Canada also has  employed  electricity  swap  contracts  to lock-in the
purchase price of electricity needed to operate its gas processing plants. These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $1.5 million, or $1.0 million after-tax.





                                       125
<PAGE>

The following  tables set forth selected  financial data  associated  with these
derivative  financial  instruments noted above that were outstanding at December
31, 2002.
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------
                                          Year of     Volumes                            Fixed        Current     Fair Value
          Type of Contract                Maturity     mmcf       Floor $    Ceiling $   Price $       Price         ($000)
----------------------------------------------------------------------------------------------------------------------------
                 Gas
<S>                                         <C>       <C>         <C>         <C>      <C>           <C>           <C>
Collars                                      2003      54,300      3.48         4.92            -     4.43-4.99     (14,681)
                                             2004      18,300      3.50         4.75            -     4.03-4.81      (3,767)

Swaps/Futures - Short Natural Gas            2003      14,751         -            -    2.91-3.52     3.87-4.99     (20,694)

Swaps/Futures - Long Natural Gas             2003      10,580         -            -    3.10-5.38     4.43-5.02       7,428

----------------------------------------------------------------------------------------------------------------------------
                                                       97,931                                                       (31,714)
----------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                                                              Fair
                               Year of    Volumes                                             Value
    Type of Contract           Maturity   Barrels      Fixed Price $      Current Price $     ($000)
---------------------------------------------------------------------------------------------------
           Oil
<S>                             <C>      <C>           <C>                  <C>            <C>
Swaps - Short Fuel Oil           2003      90,000             28.50          28.14-31.00      (145)

Swaps - Long Fuel Oil            2003     320,815       20.05-27.20          23.72-33.81     2,633
                                 2004       5,548       20.50-23.70          22.66-23.19         6
---------------------------------------------------------------------------------------------------
                                          416,363                                            2,494
---------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
                                                                                                         Fair
                               Year of                            Fixed Margin/                          Value
   Type of Contract           Maturity    Capacity      MWh          Price $          Current Price $    ($000)
--------------------------------------------------------------------------------------------------------------
      Electricity
<S>                            <C>         <C>       <C>          <C>                  <C>            <C>
Swaps - Energy                  2003                  119,680      12.70-57.80          14.15-48.09    (1,889)
                                2004                   68,800            14.00          22.25-22.34      (823)

Swaps - Capacity                2003        1,000                         7.75            7.00-9.41      (696)
--------------------------------------------------------------------------------------------------------------
                                            1,000     188,480                                          (3,408)
--------------------------------------------------------------------------------------------------------------
</TABLE>


------------------------------------------------------------------------------
Change in Fair Value of Derivative Instruments                          2002
                                                                       ($000)
------------------------------------------------------------------------------
Fair value of contracts at January 1,                              $   55,097
(Gain) on contracts realized                                          (26,204)
Fair value of new contracts when entered into during period                 -
(Decrease) in fair value of all open contracts                        (61,521)
------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31,                $  (32,628)
------------------------------------------------------------------------------


                                       126
<PAGE>

NYMEX  futures  are also used to  economically  hedge the cash flow  variability
associated  with the  purchase  of fuel for a  portion  of our  fleet  vehicles.
Further,  KeySpan  Canada has a  portfolio  of  financially-settled  natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i)  synthetically  fix the price that is paid or received by
KeySpan  Canada for  certain  physical  transactions  involving  natural gas and
natural gas liquids and (ii) transfer the price exposure of such  instruments to
other  trading  partners.  In addition,  our retail gas and  electric  marketing
subsidiary has bought options to  economically  hedge the cash flow  variability
associated  with a portion of  expected  future  natural  gas  purchases.  These
derivative financial  instruments do not qualify for hedge accounting under SFAS
133. At December  31,  2002,  these  instruments  had a net fair market value of
($0.4) million,  that was recorded on the Consolidated  Balance Sheet.  Based on
the non-hedge  designation of these instruments,  the loss was recognized in the
Consolidated Statement of Income.

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

The following  table sets forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at December 31, 2002.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
                                                                                            Fair
                           Year of      Volumes                                             Value
     Type of Contract      Maturity       mmcf        Fixed Price $     Current Price $    ($000)
-------------------------------------------------------------------------------------------------
<S>                         <C>          <C>           <C>                 <C>            <C>
Options                      2003         5,560         3.90-4.50                4.27      3,250

Swaps                        2003         2,080         3.85-4.50           4.79-4.95      1,586
-------------------------------------------------------------------------------------------------
                                          7,640                                            4,836
-------------------------------------------------------------------------------------------------
</TABLE>

Physically-Settled  Commodity  Derivative  Instruments:  On  April  1,  2002  we
implemented  Derivative  Implementation  Group  ("DIG")  Issue  C15  and  C16 of
Statement of Financial  Accounting  Standard  133,  "Accounting  for  Derivative
Instruments and Hedging Activities",  as amended and interpreted,  incorporating
SFAS 137 and SFAS 138 and  certain  implementation  issues  (collectively  "SFAS
133").  Issue C15  establishes  new criteria that must be satisfied in order for
option-type  and  forward  contracts  in  electricity  to be  exempted as normal
purchases  and  sales,  while  Issue C16  relates  to the  exemption  (as normal
purchases and normal sales) of contracts  that combine a forward  contract and a
purchased  option  contract.  Based  upon a  review  of our  physical  commodity
contracts,  we determined  that certain  contracts for the physical  purchase of
natural gas can no longer be exempted as normal  purchases from the requirements
of SFAS 133. At December 31, 2002,  the fair value of these  contracts  was $1.2
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.


                                       127
<PAGE>

Interest Rate Derivative Instruments:  During most of 2002, we had interest rate
swap agreements in which  approximately $1.3 billion of fixed rate debt had been
synthetically modified to floating rate debt. Under the terms of the agreements,
we  received  the fixed  coupon  rate  associated  with these bonds and paid the
counter-parties  a variable  interest rate that was reset on a quarterly  basis.
These swaps were  designated as fair-value  hedges and qualified for "short-cut"
hedge  accounting  treatment  under SFAS 133.  Through the  utilization of these
agreements, we reduced recorded interest expense by $35.6 million for the twelve
months ended December 31, 2002.

In early November 2002, we terminated two interest rate swap  agreements with an
aggregate  notional  amount of $1.0 billion and received  $80.9 million from our
swap counter-parties,  of which $23.4 million represented accrued swap interest.
The  difference  between  the  termination  settlement  amount and the amount of
accrued  swap  interest,  $57.4  million,  will be  amortized to earnings (as an
adjustment to interest  expense) on a level yield basis over the remaining lives
of the  originally  hedged debt  obligations.  The remaining  swap,  which had a
notional amount of $270.0  million,  and a fair market value of $15.6 million at
December 31, 2002,  was  terminated  on February  25,  2003.  We received  $18.4
million from our swap counter-parties,  of which $8.1 million represents accrued
swap interest.  The difference between the termination settlement amount and the
amount of accrued interest,  $10.3 million,  will be 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 6 "Long-Term  Debt", we intend to
redeem a portion of these  promissory  notes before the end of the first quarter
of 2003.

Additionally,  we also have an interest rate swap agreement that hedges the cash
flow  variability  associated  with  the  forecasted  issuance  of a  series  of
commercial paper offerings. The maximum length of time over which we have hedged
such cash flow  variability is through March 2003. The estimated  amount of loss
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 $0.6 million, or $0.4 million after-tax.

Weather Derivatives:  The utility tariffs associated with the KEDNE's operations
do not contain weather normalization adjustments. As a result, fluctuations from
normal weather may have a significant positive or negative effect on the results
of these  operations.  To  mitigate  a  substantial  portion  of the  effect  of
fluctuations  from normal weather on our financial  position and cash flows,  we
sold  heating  degree-day  call options and  purchased  heating  degree-day  put
options for the November 2002 - March 2003 winter  season.  With respect to sold
call  options,  KeySpan is  required  to make a payment of $40,000  per  heating
degree-day to its  counter-parties  when actual weather  experienced  during the
November 2002 - March 2003 time frame is above 4,470 heating degree days,  which
equates  to  approximately  1% colder  than  normal  weather.  With  respect  to
purchased  put options,  KeySpan  will receive a $20,000 per heating  degree day
payment  from its  counter-parties  when actual  weather is below 4,150  heating
degree days, or is  approximately  7% warmer than normal.  Based on the terms of




                                       128
<PAGE>

such  contracts,  as  discussed  in Note 1 "Summary  of  Significant  Accounting
Policies",  we account for such instruments pursuant to the requirements of EITF
99-2,  "Accounting for Weather Derivatives." In this regard, we account for such
instruments  using the  "intrinsic  value method" as set forth in such guidance.
During the fourth  quarter of 2002,  weather was 7% colder than normal and, as a
result, $3.3 million has been recorded as a reduction to revenues.

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

Fair Values of Long-Term Debt

---------------------------------------------------------------------------
                                                        December 31,
(In Thousands of Dollars)                          2002             2001
---------------------------------------------------------------------------
First Mortgage Bonds                          $   180,666      $   182,666
Notes                                           3,441,619        3,076,455
Gas Facilities Revenue Bonds                      674,828          630,845
Authority Financing Notes                          66,005           66,005
Promissory Notes                                  616,240          617,933
MEDS Equity Units                                 525,918                -
---------------------------------------------------------------------------
                                              $  5,505,276     $ 4,573,904
---------------------------------------------------------------------------


Carrying Values of Long-Term Debt

-----------------------------------------------------------------------------
                                                           December 31,
(In Thousands of Dollars)                             2002             2001
-----------------------------------------------------------------------------
First Mortgage Bonds                            $   163,625      $   179,122
Notes                                             2,985,000        2,985,000
Gas Facilities Revenue Bonds                        648,500          648,500
Authority Financing Notes                            66,005           66,005
Promissory Notes                                    602,427          602,427
MEDS Equity Units                                   460,000                -
-----------------------------------------------------------------------------
                                                $ 4,925,557      $ 4,481,054
-----------------------------------------------------------------------------


Our  subsidiary  debt is carried at an amount  approximating  fair value because
interest  rates  are  based  on  current  market  rates.   All  other  financial
instruments included in the Consolidated Balance Sheet such as cash,  commercial
paper, accounts receivable and accounts payable, are also stated at amounts that
approximate fair value.

Note 9.  Discontinued Operations

On November 8, 2000,  KeySpan acquired Midland  Enterprises LLC ("Midland"),  an
inland marine transportation subsidiary, as part of the Eastern acquisition.  In
its order  approving  the  acquisition,  the SEC  required  KeySpan to sell this
subsidiary  by  November  8,  2003  because   Midland's   operations   were  not
functionally related to KeySpan's core utility operations.  On July 2, 2002, the
sale of Midland to Ingram  Industries  Inc.  was  completed  and net proceeds of
$175.1 million were received from the sale.


                                       129
<PAGE>

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

The  following  is  selected  financial  information  for Midland for the period
January 1, 2002  through  July 2, 2002 and the year ended  December 31, 2001 and
for the period November 8, 2000 through December 31, 2000:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
(In Thousands of Dollars)                                   2002         2001         2000
--------------------------------------------------------------------------------------------
<S>                                                     <C>           <C>          <C>
Revenues                                                $ 116,149     $ 266,792    $ 40,788
Pre-tax income (loss)                                      (4,624)       18,489      (2,970)
Income tax (expense) benefit                                1,268        (7,571)      1,027
--------------------------------------------------------------------------------------------
Income (loss) from discontinued operations                 (3,356)       10,918      (1,943)
--------------------------------------------------------------------------------------------
Estimated book gain on disposal                             5,980        44,580           -
Tax expense associated with disposal                      (22,286)      (74,936)          -
--------------------------------------------------------------------------------------------
Estimated loss on disposal                                (16,306)      (30,356)          -
--------------------------------------------------------------------------------------------
Loss from discontinued operations                       $ (19,662)    $ (19,438)   $ (1,943)
--------------------------------------------------------------------------------------------
</TABLE>

Assets and liabilities of the discontinued operations are as follows:

------------------------------------------------------------------------
(In Thousands of Dollars)                                        2001
------------------------------------------------------------------------
Current assets                                                $ 139,522
Property, plant and equipment, net                              316,626
Long-term assets                                                 35,233
Current liabilities                                             (58,835)
Long-term liabilitites                                         (241,491)
------------------------------------------------------------------------
Assets held for disposal                                      $ 191,055
------------------------------------------------------------------------


Note 10.  Roy Kay Operations

During  2001,  we undertook a complete  evaluation  of the  strategy,  operating
controls  and  organizational  structure  of the Roy Kay  companies  - plumbing,
mechanical,  electrical  and  general  contracting  companies  acquired by us in
January  2000.  We decided  to  discontinue  the  general  contracting  business
conducted by these  companies  based upon our view that the general  contracting
business  is  not a  core  competency  of  these  companies.  Certain  remaining
activities  engaged in by the Roy Kay companies have been  integrated with those
of other KeySpan energy-related  businesses.  During 2002,  substantially all of
the remaining field work on outstanding  construction projects was completed. We
are now engaged in the  finalization of claims and collections and, as a result,
their operations will continue to be consolidated in our Consolidated  Financial
Statements until such time as this process is complete.


                                       130
<PAGE>

For the  year  ended  December  31,  2001,  the Roy Kay  companies  incurred  an
after-tax  loss of  $95.0  million  ($137.8  million  pre-tax)  reflecting:  (i)
unanticipated costs to complete work on certain construction projects;  (ii) the
impact of inaccuracies in the books of these companies relating to their overall
financial and operational performance; (iii) discontinuance costs of the general
contracting activities of those companies,  including the write-off of goodwill,
and certain account and retainage  receivables;  and (iv) operating losses.  For
the years ended December 31, 2002, 2001 and 2000 the Roy Kay companies  recorded
EBIT losses of $10.8 million,  $137.8 million and EBIT earnings of $1.3 million,
respectively.  KeySpan and the former Roy Kay companies are currently engaged in
litigation  relating to the  termination of the former owners,  as well as other
matters  relating  to the  acquisition  of the Roy Kay  companies.  (See  Note 7
"Contractual Obligations and Contingencies" - Legal Matters.)

Note 11. Class Action Settlement

During 2001, we reversed a previously  recorded loss provision regarding certain
pending rate refund  issues  relating to the 1989 RICO class action  settlement.
This adjustment  resulted from a favorable United States Court of Appeals ruling
received on September 28, 2001, overturning a lower court decision, and resulted
in a positive pre-tax adjustment to earnings of $33.5 million,  or $20.1 million
after-tax.  This  adjustment has been reflected as a $22.0 million  reduction to
Operations and Maintenance  expense and a reduction of $11.5 million to Interest
Expense on the Consolidated Statement of Income.

Note 12. KeySpan Gas East Corporation Summary Financial Data

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  provides gas  distribution  services to
customers  in the Long Island  counties  of Nassau and Suffolk and the  Rockaway
peninsula of Queens county.  KEDLI established a program for the issuance,  from
time to time, of up to $600 million  aggregate  principal  amount of Medium-Term
Notes, which will be fully and unconditionally guaranteed by the parent, KeySpan
Corporation.   On  February  1,  2000,  KEDLI  issued  $400  million  of  7.875%
Medium-Term  Notes due 2010.  In January 2001,  KEDLI issued an additional  $125
million of Medium-Term Notes at 6.9% due January,  2008. The following condensed
financial  statements  are required to be disclosed by SEC  regulations  and set
forth those of KEDLI, KeySpan Corporation as guarantor of the Medium- Term Notes
and our other  subsidiaries on a combined basis.  The December 31, 2001 and 2000
disclosures have been revised to separately present our other subsidiaries.


                                       131
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                  Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                          Year Ended December 31, 2002
(In Thousands of Dollars)                    Guarantor          KEDLI           Other Subsidiaries     Eliminations    Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                             <C>           <C>                   <C>                  <C>            <C>
Revenues                                      $     463       $ 810,601            $ 5,160,065        $     (463)      $ 5,970,666
Operating Expenses
  Purchased gas                                       -         379,742              1,273,531                 -         1,653,273
  Fuel and purchased power                            -               -                385,059                 -           385,059
  Operations and maintenance                     13,325          45,357              2,043,215                 -         2,101,897
  Intercompany expense                            2,772          79,826                (79,826)           (2,772)                -
  Depreciation and amortization                     (44)         65,911                448,746                 -           514,613
  Operating taxes                                (2,149)         85,614                327,186                 -           410,651
                                         ------------------------------------------------------------------------------------------
Total Operating Expenses                         13,904         656,450              4,397,911            (2,772)        5,065,493
                                         ------------------------------------------------------------------------------------------
Operating Income (Loss)                         (13,441)        154,151                762,154             2,309           905,173

Interest charges                               (200,920)        (62,520)              (295,209)          257,145          (301,504)
Other income and (deductions)                   565,366           8,152                 78,625          (633,068)           19,075
                                         ------------------------------------------------------------------------------------------
Total Other Income and (Deductions)             364,446         (54,368)              (216,584)         (375,923)         (282,429)

Income (Loss) Before Income Taxes               351,005          99,783                545,570          (373,614)          622,744

Income Taxes (Benefit)                          (26,683)         31,188                220,889                 -           225,394
                                         ------------------------------------------------------------------------------------------
Earnings from Continuing Operations           $ 377,688       $  68,595            $   324,681        $ (373,614)      $   397,350

Discontinued Operations                               -               -                (19,662)                -           (19,662)
                                         ------------------------------------------------------------------------------------------
Net Income                                    $ 377,688       $  68,595            $   305,019        $ (373,614)      $   377,688
                                         ==========================================================================================
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                  Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                               Year Ended December 31, 2001
(In Thousands of Dollars)                           Guarantor       KEDLI        Other Subsidiaries     Eliminations    Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                <C>            <C>               <C>                  <C>            <C>
Revenues                                          $     504       $ 889,693         $ 5,743,422        $     (504)      $ 6,633,115
Operating Expenses
  Purchased gas                                           -         464,780           1,706,333                 -         2,171,113
  Fuel and purchased power                                -               -             538,532                 -           538,532
  Operations and maintenance                        (24,537)         45,106           2,094,190                 -         2,114,759
  Intercompany expense                                  278          87,738             (87,738)             (278)                -
  Depreciation and amortization                       4,273          56,274             498,591                 -           559,138
  Operating taxes                                     1,094          91,204             356,626                 -           448,924
                                             ---------------------------------------------------------------------------------------
Total Operating Expenses                            (18,892)        745,102           5,106,534              (278)        5,832,466
                                             ---------------------------------------------------------------------------------------
Operating Income (Loss)                              19,396         144,591             636,888              (226)          800,649

Interest charges                                   (230,618)        (65,206)           (264,286)          206,640          (353,470)
Other income and (deductions)                       426,346           9,721              18,455          (447,316)            7,206
                                             ---------------------------------------------------------------------------------------
Total Other Income and (Deductions)                 195,728         (55,485)           (245,831)         (240,676)         (346,264)

Income (Loss) Before Income Taxes                   215,124          89,106             391,057          (240,902)          454,385

Income Taxes (Benefit)                               (9,130)         28,319             191,504                 -           210,693
                                             ---------------------------------------------------------------------------------------
Earnings from Continuing Operations               $ 224,254       $  60,787         $   199,553        $ (240,902)      $   243,692

Discontinued Operations                                   -               -             (19,438)                -           (19,438)
                                             ---------------------------------------------------------------------------------------
Net Income                                        $ 224,254       $  60,787         $   180,115        $ (240,902)      $   224,254
                                             =======================================================================================
</TABLE>


                                       132
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                  Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                              Year Ended December 31, 2000
(In Thousands of Dollars)                             Guarantor       KEDLI       Other Subsidiaries   Eliminations    Consolidated
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>           <C>            <C>                 <C>            <C>
Revenues                                            $   1,799       $ 794,965      $ 4,285,737       $   (1,799)      $ 5,080,702
Operating Expenses
  Purchased gas                                             -         408,087        1,000,593                -         1,408,680
  Fuel and purchased power                                  -               -          460,841                -           460,841
  Operations and maintenance                           61,520         127,780        1,535,611                -         1,724,911
  Intercompany expense                                  1,799          10,718          (10,718)          (1,799)                -
  Depreciation and amortization                         4,273          46,017          280,632                -           330,922
  Operating taxes                                      (8,172)         92,684          337,424                -           421,936
                                               -----------------------------------------------------------------------------------
Total Operating Expenses                               59,420         685,286        3,604,383           (1,799)        4,347,290
                                               -----------------------------------------------------------------------------------
Operating Income (Loss)                               (57,621)        109,679          681,354                -           733,412

Interest charges                                      (97,007)        (53,656)        (118,044)          67,393          (201,314)
Other income and (deductions)                         417,411            (707)         (67,606)        (361,184)          (12,086)
                                               -----------------------------------------------------------------------------------
Total Other Income and (Deductions)                   320,404         (54,363)        (185,650)        (293,791)         (213,400)

Income (Loss) Before Income Taxes                     262,783          55,316          495,704         (293,791)          520,012

Income Taxes (Benefit)                                (38,024)         18,362          236,924                -           217,262
                                               -----------------------------------------------------------------------------------
Earnings from Continuing Operations                 $ 300,807       $  36,954      $   258,780       $ (293,791)      $   302,750

Discontinued Operations                                     -               -           (1,943)               -            (1,943)
                                               -----------------------------------------------------------------------------------
Net Income                                          $ 300,807       $  36,954      $   256,837       $ (293,791)      $   300,807
                                               ===================================================================================
</TABLE>


                                       133
<PAGE>


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
------------------------------------------------------------------------------------------------------------------------------------
                                                                                  December 31, 2002
                                                                                       Other
                                                    Guarantor          KEDLI        Subsidiaries    Eliminations        Consolidated
                                           -----------------------------------------------------------------------------------------
ASSETS
<S>                                               <C>             <C>              <C>               <C>                <C>
Current Assets
   Cash and 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          432,816                 -            513,779
                                           -----------------------------------------------------------------------------------------
                                                     114,047          294,190        1,808,212                 -          2,216,449
                                           -----------------------------------------------------------------------------------------
Equity Investments                                 3,797,964                -          792,050        (4,330,826)           259,188
                                           -----------------------------------------------------------------------------------------
Property
   Gas                                                     -        1,771,780        4,352,501                 -          6,124,281
   Other                                                   -                -        4,807,724                 -          4,807,724
   Accumulated depreciation and depletion                  -         (322,236)      (3,392,169)                -         (3,714,405)
                                           -----------------------------------------------------------------------------------------
                                                           -        1,449,544        5,768,056                 -          7,217,600
                                           -----------------------------------------------------------------------------------------

Intercompany Accounts Receivable                   3,619,515           54,549          354,747        (4,028,811)                 -

Deferred Charges                                     339,443          195,369        2,386,257                 -          2,921,069

                                           -----------------------------------------------------------------------------------------
Total Assets                                     $ 7,870,969      $ 1,993,652     $ 11,109,322      $ (8,359,637)      $ 12,614,306
                                           =========================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                              $   240,571      $    68,772     $    752,306      $          -       $  1,061,649
   Commercial paper                                  915,697                -                -                 -            915,697
   Other current liabilities                               -          104,975          137,907                 -            242,882
                                           ----------------------------------------------------------------------------------------
                                                   1,156,268          173,747          890,213                 -          2,220,228
                                           ----------------------------------------------------------------------------------------
Intercompany Accounts Payable                              -          233,392        1,714,035        (1,947,427)                 -
                                           ----------------------------------------------------------------------------------------
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        3,645,115        (4,330,826)         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        7,040,892        (6,412,210)         8,252,522
                                           -----------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies                  -                -          230,421                 -            230,421
                                           -----------------------------------------------------------------------------------------
Total Liabilities and Capitalization             $ 7,870,969      $ 1,993,652     $ 11,109,322      $ (8,359,637)      $ 12,614,306
                                           =========================================================================================
</TABLE>


                                       134
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
------------------------------------------------------------------------------------------------------------------------------------
                                                                                December 31, 2001
                                                                                       Other
                                                     Guarantor         KEDLI        Subsidiaries      Eliminations      Consolidated
                                               -------------------------------------------------------------------------------------
ASSETS
<S>                                                <C>            <C>               <C>              <C>                 <C>
Current Assets
   Cash and temporary cash investments            $         -     $         -       $   159,252     $          -       $    159,252
   Accounts receivable, net                            25,037         178,464         1,069,098                -          1,272,599
   Other current assets                                   658         112,317           453,661                -            566,636
                                               -------------------------------------------------------------------------------------
                                                       25,695         290,781         1,682,011                -         1,998,487
                                               -------------------------------------------------------------------------------------
Assets Held for Disposal                                    -               -           191,055                -            191,055
Equity Investments                                  3,539,546               -           756,111       (4,072,408)           223,249
                                               -------------------------------------------------------------------------------------
Property
   Gas                                                      -       1,629,963         4,074,894                -          5,704,857
   Other                                                    -               -         4,231,262                -          4,231,262
   Accumulated depreciation and depletion                   -        (294,400)       (3,035,788)               -         (3,330,188)
                                               -------------------------------------------------------------------------------------
                                                            -       1,335,563         5,270,368                -          6,605,931
                                               -------------------------------------------------------------------------------------

Intercompany Accounts Receivable                    3,578,204          54,549           445,947       (4,078,700)                 -

Deferred Charges                                      156,001         199,855         2,415,028                -          2,770,884

                                               -------------------------------------------------------------------------------------
Total Assets                                      $ 7,299,446     $ 1,880,748       $10,760,520     $ (8,151,108)      $ 11,789,606
                                               =====================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                               $   455,947     $   115,557       $   519,926     $          -       $  1,091,430
   Commercial paper                                 1,048,450               -                 -                -          1,048,450
   Other current liabilities                             (255)         23,844           221,240                -            244,829
                                               -------------------------------------------------------------------------------------
                                                    1,504,142         139,401           741,166                -          2,384,709
                                               -------------------------------------------------------------------------------------
Intercompany Accounts Payable                               -         324,592         1,667,846        (1,992,438)                 -
                                               -------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                                   (60,261)          4,772           653,561                -            598,072
Other deferred credits and liabilities                320,510         100,452           521,152                -            942,114
                                               -------------------------------------------------------------------------------------
                                                      260,249         105,224         1,174,713                -          1,540,186
                                               -------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                         2,823,177         610,627         3,529,206       (4,072,408)         2,890,602
Preferred stock                                        84,077               -                 -                -             84,077
Long-term debt                                      2,627,801         700,904         3,455,206       (2,086,262)         4,697,649
                                               -------------------------------------------------------------------------------------
Total Capitalization                                5,535,055       1,311,531         6,984,412       (6,158,670)         7,672,328
                                               -------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies                   -               -           192,383                -            192,383
                                               -------------------------------------------------------------------------------------
Total Liabilities and Capitalization              $ 7,299,446     $ 1,880,748       $10,760,520     $ (8,151,108)      $ 11,789,606
                                               =====================================================================================
</TABLE>


                                       135
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
------------------------------------------------------------------------------------------------------------------------------------
                                                                                         Year Ended December 31, 2002
                                                                 ------------------------------------------------------------------
                                                                                                         Other
                                                                        Guarantor       KEDLI         Subsidiaries     Consolidated
                                                                 ------------------------------------------------------------------
<S>                                                                     <C>           <C>              <C>             <C>
Operating Activities
   Net Cash (Used in) Provided by Operating Activities                 $ (97,981)     $ 191,826        $ 715,232         $ 809,077
                                                                 ------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                        -       (148,418)        (985,459)       (1,133,877)
   Other                                                                       -              -          147,531           147,531
                                                                 ------------------------------------------------------------------
Net Cash (Used in) Investing Activities                                        -       (148,418)        (837,928)         (986,346)
                                                                 ------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                                  86,710              -                -            86,710
   Issuance (payment) of debt, net                                       327,247              -          (35,711)          291,536
   Common and preferred stock dividends paid                            (256,656)             -                -          (256,656)
   Termination of interest rate swaps and other                           70,299              -           (3,255)           67,044
   Net intercompany accounts                                             (41,311)       (36,936)          78,247                 -
                                                                 ------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities                      186,289        (36,936)          39,281           188,634
                                                                 ------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents                   $  88,308      $   6,472        $ (83,415)        $  11,365
Cash and Cash Equivalents at Beginning of Period                               -              -          159,252           159,252
                                                                 ------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                             $  88,308      $   6,472        $  75,837         $ 170,617
                                                                 ==================================================================
</TABLE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
-----------------------------------------------------------------------------------------------------------------------------------
                                                                           Year Ended December 31, 2001
                                                               --------------------------------------------------------------------
                                                                                                       Other
                                                                      Guarantor        KEDLI         Subsidiaries     Consolidated
                                                               --------------------------------------------------------------------
<S>                                                                <C>             <C>                <C>             <C>
Operating Activities
   Net Cash Provided by Operating Activities                         $ 121,028       $ 64,294          $ 704,859        $  890,181
                                                               --------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                      -       (131,568)          (928,191)       (1,059,759)
   Other                                                                     -              -             18,452            18,452
                                                               --------------------------------------------------------------------
Net Cash (Used in) Investing Activities                                      -       (131,568)          (909,739)       (1,041,307)
                                                               --------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                                88,786              -                  -            88,786
   Issuance (payment) of debt, net                                     248,213        125,000              3,706           376,919
   Common and preferred stock dividends paid                          (251,502)             -                  -          (251,502)
   Other                                                                10,582              -              2,264            12,846
   Net intercompany accounts                                          (217,107)       (57,726)           274,833                 -
                                                               --------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities                   (121,028)        67,274            280,803           227,049
                                                               --------------------------------------------------------------------

Net Increase in Cash and Cash Equivalents                            $       -       $      -          $  75,923        $   75,923
Cash and Cash Equivalents at Beginning of Period                             -              -             83,329            83,329
                                                               --------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                           $       -       $      -          $ 159,252        $  159,252
                                                               ====================================================================
</TABLE>


                                       136
<PAGE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
-----------------------------------------------------------------------------------------------------------------------------------
                                                                            Year Ended December 31, 2000
                                                              ---------------------------------------------------------------------
                                                                                                        Other
                                                                      Guarantor          KEDLI       Subsidiaries     Consolidated
                                                              ---------------------------------------------------------------------
<S>                                                                 <C>              <C>               <C>           <C>
Operating Activities
   Net Cash Provided by Operating Activities                          $ 245,497       $ 112,738        $  80,491        $ 438,726
                                                              ---------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                       -        (114,977)        (518,058)        (633,035)
   Other                                                             (1,946,043)              -         (292,732)      (2,238,775)
                                                              ---------------------------------------------------------------------
Net Cash (Used in) Investing Activities                              (1,946,043)       (114,977)        (810,790)      (2,871,810)
                                                              ---------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                                 72,289               -                -           72,289
   Receipt/payment of dividends                                               -        (125,000)         125,000                -
   Redemption of preferred stock                                       (363,000)              -                -         (363,000)
   Issuance (payment) of debt, net                                    2,741,937         400,000         (107,975)       3,033,962
   Debt received (paid)                                                 397,000        (397,000)               -                -
   Common and preferred stock dividends paid                           (260,001)              -                -         (260,001)
   Termination of interest rate swaps and other                         (41,799)              -          (53,640)         (95,439)
   Net intercompany accounts                                           (845,880)        124,239          721,641                -
                                                              ---------------------------------------------------------------------
Net Cash Provided by Financing Activities                             1,700,546           2,239          685,026        2,387,811
                                                              ---------------------------------------------------------------------
Net (Decrease) in Cash and Cash Equivalents                           $       -       $       -        $ (45,273)       $ (45,273)
Cash and Cash Equivalents at Beginning of Period                              -               -          128,602          128,602
                                                              ---------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                            $       -       $       -        $  83,329        $  83,329
                                                              =====================================================================
</TABLE>








                                       137
<PAGE>

Note 13. Eastern/EnergyNorth Acquisition

On November 8, 2000,  we purchased all of the  outstanding  stock of Eastern for
$64.56  per  share in cash and all of the  outstanding  common  stock of ENI for
$61.46 per share in cash. Itemization of the purchase price is as follows:

--------------------------------------------------------------
(In Thousands of Dollars)
--------------------------------------------------------------
Eastern Enterprises Common Stock                  $ 1,754,400
EnergyNorth Common Stock                              204,200
Transaction costs                                      10,200
Other                                                   2,000
--------------------------------------------------------------
Total Consideration                               $ 1,970,800
--------------------------------------------------------------


The transactions have been accounted for using the purchase method of accounting
for business combinations.  Accordingly, the accompanying Consolidated Statement
of Income  includes  Eastern and ENI results  commencing  November 8, 2000.  The
purchase  price was allocated to the net assets  acquired  based upon their fair
value.  The historical cost basis of Eastern's and ENI's assets and liabilities,
with minor  exceptions,  was  determined  to represent the fair value due to the
existence  of  regulatory-approved   rate  plans  based  upon  the  recovery  of
historical costs and a fair return thereon. The allocation of the purchase price
to the assets and liabilities acquired from Eastern and ENI was as follows:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)                             Eastern                ENI                 Total
--------------------------------------------------------------------------------------------------------
<S>                                                 <C>                   <C>               <C>
Gas Plant                                          $   599,900            $ 124,800         $   724,700
Other Plant (non - regulated)                          704,600                    -             704,600
Investments and regulatory assets                       82,100                    -              82,100
Current assets                                         322,500               40,200             362,700
Other deferred charges                                  63,300               14,700              78,000
Current liabilities                                   (333,400)             (77,000)           (410,400)
Other liabilities                                     (498,000)             (23,600)           (521,600)
Long-term debt                                        (502,100)             (45,200)           (547,300)
--------------------------------------------------------------------------------------------------------
Net assets acquired*                               $   438,900            $  33,900         $   472,800
Goodwill                                             1,325,600              172,400           1,498,000
--------------------------------------------------------------------------------------------------------
Total purchase price                               $ 1,764,500            $ 206,300         $ 1,970,800
--------------------------------------------------------------------------------------------------------
</TABLE>

*  Certain   non-regulated   long-term  assets  of  Eastern  were  increased  by
approximately  $25  million to reflect the fair value of such assets at the date
of  acquisition.  Further,  no  intangible  assets were acquired as part of this
transaction.






                                       138
<PAGE>

The  following  is  the  comparative   unaudited  proforma  condensed  financial
information  for the year ended  December  31, 2000.  The  proforma  disclosures
reflect the results of the operations of Eastern and ENI as if our  acquisitions
were consummated on January 1, 2000.

--------------------------------------------------------------------------------
                                                                   Year Ended
(In Thousands of Dollars, Except Per Share Amounts)            December 31, 2000
--------------------------------------------------------------------------------
Revenues                                                           $ 6,130,158
Operating Income                                                   $   671,081
Net Income                                                         $   114,393
Earnings Per Share                                                 $      0.71
--------------------------------------------------------------------------------


Included  in the 2000  pro-forma  earnings  are  merger  related  costs of $76.0
million,  after-tax,  recorded  by  Eastern  and  ENI  in  connection  with  our
acquisition of these companies.  Excluding these costs,  pro-forma earnings were
$1.27 per share for the year ended December 31, 2000.  These  pro-forma  results
may not be indicative of future results.  Further,  the  consolidated  pro-forma
results  for 2000 do not take into  account:  (i)  continued  gas  sales  growth
throughout  our  service  territories,  especially  on  Long  Island  and in New
England;  (ii) earnings  enhancement  from our gas  exploration  and  production
operations; and (iii) the continued successful integration of acquired companies
providing energy-related services within our Energy Services segment.

Note 14.   Workforce Reduction Programs

As a result of the Eastern and ENI acquisitions, we implemented early retirement
and  severance  programs  in an  effort  to  reduce  our  workforce.  The  early
retirement  program  was  completed  in  December  2000,  at which time  KeySpan
recorded a charge of $51.4 million to reflect  termination  benefits  related to
employees  who  voluntarily  elected  early  retirement.  In  addition,  KeySpan
recorded a $13.8 million liability  associated with severance programs;  Eastern
and ENI had  previously  recorded an additional  liability of $8.9 million.  The
combined liability, therefore, was $22.7 million. During the year ended December
31, 2001,  we reduced  this  liability by $4.1 million as a result of lower than
anticipated  costs per  employee  and  recorded  a  corresponding  reduction  to
goodwill. During 2002, we paid $3.5 million for the program and, in total, $13.6
million was  distributed to employees  during the past two years.  The remaining
liability of $5.0 million was reversed and recorded to earnings in 2002.

Note 15.  Shareholder Rights Plan

On March 30, 1999, our Board of Directors adopted a Shareholder Rights Plan (the
"Plan")  designed to protect  shareholders in the event of a proposed  takeover.
The Plan  creates a  mechanism  that would  dilute the  ownership  interest of a
potential  unauthorized  acquirer.  The Plan  establishes  one  preferred  stock
purchase "right" for each  outstanding  share of common stock to shareholders of
record on April 14, 1999. Each right, when  exercisable,  entitles the holder to
purchase  1/100th of a share of Series D Preferred  Stock, at a price of $95.00.
The rights generally become  exercisable  following the acquisition of more than
20 percent of our common  stock  without the consent of the Board of  Directors.
Prior to  becoming  exercisable,  the  rights  are  redeemable  by the  Board of
Directors  for $0.01 per right.  If not so  redeemed,  the rights will expire on
March 30, 2009.


                                       139
<PAGE>

Note 16. Subsequent Events

Subsequent to December 31, 2002, the following events ocurred:

On January 17,  2003,  KeySpan  sold 13.9  million  shares of common  stock in a
public  offering.  The offering  generated  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 sale were used
initially to pay down commercial paper.

On February 25, 2003 we terminated an interest  rate swap  agreement  that had a
notional  amount  of $270  million  and  received  $18.4  million  from our swap
counter-parties  of which $8.1 million  represents  accrued swap  interest.  The
difference  between the termination  settlement amount and the amount of accrued
swap interest,  $10.3 million,  will be recorded  through  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 6 "Long-Term  Debt", we intend to
redeem a portion of these  promissory  notes before the end of the first quarter
of 2003.

On February 26, 2003, we reduced our ownership  interest in Houston  Exploration
from 66% to approximately 56% following the repurchase,  by Houston Exploration,
of 3 million shares of stock owned by KeySpan. The net proceeds of approximately
$79 million  received in connection  with this  repurchase were used to pay down
commercial paper.  Additionally  there is an  over-allotment  option for 300,000
shares,  which if  exercised  would  further  reduce  our  ownership  in Houston
Exploration to 55%.

In connection with the class action lawsuit discussed in Note 7, regarding among
other things,  alleged  violations  of Sections  10(b) and 20(a) of the Exchange
Act,  on March 18, 2003 the court  granted our motion to dismiss the  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. (Unaudited)

Note 17. Supplemental Gas and Oil Disclosures (Unaudited)

This information  includes amounts  attributable to 100% of Houston  Exploration
and KeySpan Exploration and Production,  LLC at December 31, 2002.  Shareholders
other than  KeySpan  had a minority  interest  of  approximately  34% in Houston
Exploration  at  December  31,  2002,  33% in 2001 and 30% in 2000.  Gas and oil
operations, and reserves, were located in the United States in all years.


                                       140
<PAGE>

<TABLE>
<CAPTION>
Capitalized Costs Relating to Gas and Oil Producing Activities
---------------------------------------------------------------------------------------------------------------------------------
                                                                                              (In Thousands of Dollars)
---------------------------------------------------------------------------------------------------------------------------------
At December 31,                                                                         2002             2001             2000
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>              <C>              <C>
Unproved properties not being amortized                                            $   110,623       $  195,478       $  166,479
Properties being amortized - productive and nonproductive                            1,917,287        1,590,014        1,235,436
---------------------------------------------------------------------------------------------------------------------------------
Total capitalized costs                                                              2,027,910        1,785,492        1,401,915
Accumulated depletion                                                                 (968,713)        (791,194)        (617,628)
---------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs                                                              $ 1,059,197       $  994,298       $  784,287
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
Costs Incurred in Property Acquisition, Exploration and Development Activities
-------------------------------------------------------------------------------------------------------------------
                                                                               (In Thousands of Dollars)
-------------------------------------------------------------------------------------------------------------------
At December 31,                                                         2002               2001              2000
-------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>               <C>                <C>
Acquisition of properties -
     Unproved properties                                            $  14,600          $  31,718         $   7,992
     Proved properties                                                 90,004             85,435            40,960
Exploration                                                            28,343             74,497            70,511
Development                                                           139,108            191,927           111,078
-------------------------------------------------------------------------------------------------------------------
Total costs incurred                                                $ 272,055          $ 383,577         $ 230,541
-------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
Costs included in development costs to develop proved  undeveloped  reserves for
the years ended  December  31,  2002,  2001 and 2000 were $11.0  million,  $19.9
million and $9.7 million, respectively.

Results of Operations from Gas and Oil Producing Activities*
--------------------------------------------------------------------------------------------------
                                                              (In Thousands of Dollars)
--------------------------------------------------------------------------------------------------
At December 31,                                             2002           2001            2000
--------------------------------------------------------------------------------------------------
<S>                                                       <C>             <C>            <C>
Revenues                                               $   356,233      $  396,734      $ 274,209
Production and lifting costs                                44,822          37,574         33,508
Depletion                                                  177,519         173,566         90,280
--------------------------------------------------------------------------------------------------
Total expenses                                             222,341         211,140        123,788
--------------------------------------------------------------------------------------------------
Income before taxes                                        133,892         185,594        150,421
Income taxes                                                45,836          64,118         51,767
--------------------------------------------------------------------------------------------------
Results of operations                                  $    88,056      $  121,476      $  98,654
--------------------------------------------------------------------------------------------------
</TABLE>

* (Excluding corporate overhead and interest costs)

                                       141
<PAGE>

<TABLE>
<CAPTION>
Summary of Production and Lifting Costs
-----------------------------------------------------------------------------------------------------
                                                                       (In Thousands of Dollars)
-----------------------------------------------------------------------------------------------------
At December 31,                                                    2002           2001          2000
-----------------------------------------------------------------------------------------------------
<S>                                                             <C>            <C>           <C>
Pumping, gauging and other labor                               $  7,846       $  5,342      $  6,199
Compressors and other rental equipment                            4,135          3,023         1,990
Property taxes and insurance                                      6,801          3,640         2,195
Transportation                                                    2,131          3,162         3,430
Processing fees                                                   3,078          2,267           622
Workover and well stimulation                                     2,348          1,478         3,310
Repairs, maintenance and supplies                                 2,972          2,204         2,177
Fuel and chemicals                                                2,582          1,424           818
Environmental, regulatory and other                               3,307          3,639         3,010
Severance taxes                                                   9,622         11,395         9,757
-----------------------------------------------------------------------------------------------------
Total production and lifting costs                             $ 44,822       $ 37,574      $ 33,508
-----------------------------------------------------------------------------------------------------
</TABLE>

The gas and oil reserves information is based on estimates of proved reserves
attributable to the interest of Houston Exploration and KeySpan Exploration and
Production, LLC as of December 31 for each of the years presented. These
estimates principally were prepared by independent petroleum consultants. Proved
reserves are estimated quantities of natural gas and crude oil which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions.

<TABLE>
<CAPTION>
Reserve Quantity Information Natural Gas (MMcf)
----------------------------------------------------------------------------------------------
At December 31,                                          2002           2001            2000
----------------------------------------------------------------------------------------------
<S>                                                   <C>             <C>            <C>
Proved Reserves
   Beginning of year                                   585,659         545,858        534,306
   Revisions of previous estimates                     (15,324)        (39,994)         4,479
   Extensions and discoveries                          105,798          86,401         77,645
   Production                                           (2,669)        (90,754)       (78,493)
   Purchases of reserves in place                       48,777          84,148          7,921
   Sales of reserves in place                         (107,507)              -              -
----------------------------------------------------------------------------------------------
Proved reserves - End of year (1)                      614,734         585,659        545,858
Proved developed reserves
   Beginning of year                                   448,921         431,536        399,482
   End of Year (2)                                     435,629         448,921        431,536
----------------------------------------------------------------------------------------------
</TABLE>
(1)  Includes minority interest of 208,516,  188,077, and 167,730 in 2002, 2001,
     and 2000, respectively.

(2)  Includes  minority  interest of 148,811,  148,593 and 133,271in 2002, 2001,
     and 2000, respectively.


                                       142
<PAGE>

<TABLE>
<CAPTION>
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
--------------------------------------------------------------------------------------------------
At December 31,                                             2002              2001            2000
--------------------------------------------------------------------------------------------------
<S>                                                        <C>              <C>            <C>
Proved reserves
Beginning of Year                                           10,234           7,912          3,136
Revisions of previous estimates                                 21            (289)           108
Extension and discoveries                                        -           3,061          4,326
Production                                                    (166)           (536)          (320)
Purchases of reserves in place                                   -             115            662
Sales of reserves in place                                    (469)            (29)             -
--------------------------------------------------------------------------------------------------
Proved reserves - End of year (1)                            9,620          10,234          7,912
Proved developed reserves
Beginning of year                                            2,479           2,126          2,059
End of year (2)                                              2,413           2,479          2,126
--------------------------------------------------------------------------------------------------
</TABLE>

(1) Includes  minority  interest of 2,256,  2,186 and 1,695 in 2002,  2001,  and
2000, respectively.  (2) Includes minority interest of 824, 821 and 573 in 2002,
2001, and 2000, respectively.

The  standardized  measure of  discounted  future net cash flows was prepared by
applying year-end prices of gas and oil to the proved reserves. The standardized
measure  does not  purport,  nor should it be  interpreted,  to present the fair
value of gas and oil reserves of Houston  Exploration or KeySpan Exploration and
Production  LLC. An estimate of fair value would also take into  account,  among
other  things,  the recovery of reserves  not  presently  classified  as proved,
anticipated  future  changes  in prices and costs,  and a discount  factor  more
representative  of the time  value of money and the risks  inherent  in  reserve
estimates.

<TABLE>
<CAPTION>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                             (In Thousands of Dollars)
-----------------------------------------------------------------------------------------------------------------------------------
At December 31,                                                                     2002                2001                2000
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>    <C>          <C>                 <C>
Future cash flows                                                              $ 2,951,622         $ 1,580,077         $ 5,415,587
Future costs-
  Production                                                                      (495,097)           (316,421)           (558,384)
  Development                                                                     (263,926)           (227,158)           (182,242)
-----------------------------------------------------------------------------------------------------------------------------------
Future net inflows before income tax                                             2,192,599           1,036,498           4,674,961
Future income taxes                                                               (559,853)           (221,324)         (1,299,965)
-----------------------------------------------------------------------------------------------------------------------------------
Future net cash flows                                                            1,632,746             815,174           3,374,996
10% discount factor                                                               (528,829)           (228,988)         (1,209,237)
-----------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows (1)                   $ 1,103,917           $ 586,186         $ 2,165,759
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Includes minority interest of 361,435, 182,555 and 653,046 in 2002, 2001 and
2000, respectively

Costs  included  in future  development  costs  related  to  proved  undeveloped
reserves  for the years  ending  December  31,  2003,  2004 and 2005 are  $155.6
million, $38.2 million and $7.0 million, respectively.


                                       143
<PAGE>

<TABLE>
<CAPTION>
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserve Quantities
-------------------------------------------------------------------------------------------------------------------------------
                                                                                         (In Thousands of Dollars)
-------------------------------------------------------------------------------------------------------------------------------
 At December 31,                                                                2002                2001                2000
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>                <C>                 <C>
 Standardized measure - beginning of year                                  $   586,186         $ 2,165,759         $   480,632
 Sales and transfers, net of production costs                                 (285,603)           (359,163)           (240,702)
 Net change in sales and transfer prices, net
      of production costs                                                      589,632          (2,250,252)          2,142,932
 Extensions and discoveries and improved
      recovery, net of related costs                                           242,055             117,326             472,658
 Changes in estimated future development costs                                  (6,453)            (23,395)            (38,839)
 Development costs incurred during the period
      that reduced future development costs                                     42,075              75,652              77,197
 Revisions of quantity estimates                                               (36,368)            (52,928)             24,650
 Accretion of discount                                                          68,986             293,581              54,460
 Net change in income taxes                                                   (215,369)            666,373            (706,074)
 Net purchases of reserves in place                                             99,741              51,674              23,118
 Sales of reserves in place                                                    (31,488)               (133)                  -
 Changes in production rates (timing) and other                                 50,523             (98,308)           (124,273)
-------------------------------------------------------------------------------------------------------------------------------
 Standardized measure - end of year                                        $ 1,103,917         $   586,186         $ 2,165,759
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
Average Sales Prices and Production Costs Per Unit
---------------------------------------------------------------------------------------------------------------------
Year Ended December 31,                                                         2002            2001           2000
---------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>            <C>             <C>
Average Sales Price*
     Natural gas ($/Mcf)                                                         3.16           4.09            3.97
     Oil, condensate and natural gas liquid ($/Bbl)                             24.06          23.09           27.29
Production cost per equivalent Mcf ($)                                           0.42            0.4            0.42
---------------------------------------------------------------------------------------------------------------------
</TABLE>
*Represents  the cash price  received  which  excludes the effect of any hedging
transactions.


Acreage
-------------------------------------------------------------------------------
At December  31, 2002                           Gross                    Net
-------------------------------------------------------------------------------
Producing                                       396,988                262,659
Undeveloped                                     267,666                228,428
-------------------------------------------------------------------------------


Number of Producing Wells
------------------------------------------------------------------------------
At December 31, 2002                           Gross                      Net
------------------------------------------------------------------------------
Gas wells                                     1,593.0                   861.3
Oil wells                                        10.0                     6.1
------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Drilling Activity (Net)
--------------------------------------------------------------------------------------------------------------------------
At December 31,                                 2002                         2001                           2000
--------------------------------------------------------------------------------------------------------------------------
                                   Producing    Dry    Total     Producing    Dry     Total      Producing   Dry   Total
                               -------------------------------------------------------------------------------------------
<S>                                  <C>       <C>    <C>          <C>       <C>      <C>          <C>       <C>    <C>
Net developmental wells               65.1      9.4    74.5         51.9      10.2     62.1         40.4      4.4    44.8
Net exploratory wells                  4.0      2.2     6.2          5.3       4.3      9.6          5.1      1.7     6.8
--------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       144

<PAGE>

Wells in Process
--------------------------------------------------------------------------------
At December 31, 2002                       Gross                   Net
--------------------------------------------------------------------------------
Exploratory                                 5.0                    2.8
Developmental                               7.0                    6.2
--------------------------------------------------------------------------------

Note 18.  Summary of Quarterly Information (Unaudited)

The  following is a table of financial  data for each quarter of KeySpan's  year
ended December 31, 2002.
<TABLE>
<CAPTION>
                                                                                           Quarter Ended
--------------------------------------------------------------------------------------------------------------------------------
    (In Thousands of Dollars, Except Per Share Amounts)             3/31/02          6/30/02          9/30/02          12/31/02
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>              <C>              <C>              <C>
Operating revenues                                                 1,871,366        1,215,911        1,076,066        1,807,323
Earnings before interest charges and income taxes                    406,063          112,272           86,230          319,683
Earnings from continuing operations                                  214,631           29,174            4,964          148,581
Loss from discountinued operations                                         -          (19,662)               -                -
Earnings for common stock                                            213,155            8,036            3,629          147,115
Basic earnings per common share from continuing operations
less preferred stock dividends (a)                                      1.52             0.20             0.03             1.03
Basic earnings per common share from discountinued
operations (a)                                                             -            (0.14)               -                -
Basic earnings per common share (a)                                     1.52             0.06             0.03             1.03
Diluted earnings per common share (a)                                   1.51             0.06             0.02             1.03
Dividends declared                                                     0.445            0.445            0.445            0.445
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Quarterly  earnings  per share are  based on the  average  number of shares
outstanding during each quarter. Because of the changing number of common shares
outstanding  in each quarter,  the sum of quarterly  earnings per share does not
necessarily equal earnings per share for the year.

The  following is a table of financial  data for each quarter of KeySpan's  year
ended December 31, 2001.

<TABLE>
<CAPTION>
                                                                                   Quarter Ended
-----------------------------------------------------------------------------------------------------------------------------------
     (In Thousands of Dollars, Except Per Share Amounts)            3/31/01        6/30/01 (a)      9/30/01 (b)       12/31/01 (c)
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>             <C>              <C>               <C>
Operating revenues                                                 2,575,088       1,339,302        1,102,439         1,616,286
Earnings before interest charges and income taxes                    462,104          85,224           49,792           210,735
Earnings (loss) from continuing operations                           224,114         (10,417)         (37,427)           67,422
Earnings (loss) from discountinued operations                            661           3,892            2,253           (26,244)
Earnings (loss) for common stock                                     223,299          (8,001)         (36,647)           39,699
Basic earnings per common share from continuing operations
less preferred stock dividneds (d)                                      1.63           (0.09)           (0.28)             0.48
Basic earnings per common share from discountinued operations (d)          -            0.03             0.02             (0.19)
Basic earnings per common share (d)                                     1.63           (0.06)           (0.26)             0.29
Diluted earnings per common share (d)                                   1.61           (0.06)           (0.26)             0.28
Dividends declared                                                     0.445           0.445            0.445             0.445
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(a) Reflects costs to complete work on certain construction projects, as well as
operating losses of the Roy Kay Companies of $35.6 million after-tax.

(b)  Reflects the reversal of a previously  recorded  loss  provision  regarding
certain  pending rate refund issues of $20.1  after-tax.  Also  includes  losses
incurred by the Roy Kay  Companies  of $56.6  million  after-tax  related to the
discontinuance of the general contracting activities of these companies.

(c)  Reflects  an  after-tax  non-cash  impairment  charge of $26.2  million  to
recognize  the effect of lower  wellhead  prices on the  valuation of proved gas
reserves, as well as after-tax operating losses of the Roy Kay Companies of $2.8
million.

(d)  Quarterly  earnings  per share are  based on the  average  number of shares
outstanding during each quarter. Because of the changing number of common shares
outstanding  in each quarter,  the sum of quarterly  earnings per share does not
necessarily equal earnings per share for the year.

                                       145
<PAGE>




INDEPENDENT AUDITORS' REPORT

To the Shareholders and Board of Directors of KeySpan Corporation:

We  have  audited  the  accompanying   Consolidated  Balance  Sheet  of  KeySpan
Corporation  and  subsidiaries  (the  Company) as of December 31, 2002,  and the
related  Consolidated  Statements of Income,  Retained  Earnings,  Comprehensive
Income,  Capitalization,  and Cash Flows for the year then ended. Our audit also
included  the  consolidated  financial  statement  schedule,  for the year ended
December  31,  2002,  listed  in the  Index at Item 14 (a).  These  consolidated
financial  statements and the consolidated  financial statement schedule are the
responsibility of the Company's management.  Our responsibility is to express an
opinion  on  these  consolidated   financial  statements  and  the  consolidated
financial schedule based on our audit. The consolidated  financial statements of
KeySpan  Corporation for the years ended December 31, 2001 and 2000 were audited
by other auditors who have ceased  operations.  Their report,  dated February 4,
2002, expressed an unqualified opinion on those statements.

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

In our opinion,  such consolidated  financial  statements present fairly, in all
material  respects,  the  financial  position  of the  KeySpan  Corporation  and
subsidiaries  as of December 31, 2002,  and the results of their  operations and
their  cash  flows  for the  year  then  ended  in  conformity  with  accounting
principles  generally  accepted  in the United  States of  America.  Also in our
opinion,  such consolidated  financial  statement  schedule,  when considered in
relation  to the  basic  consolidated  financial  statements  taken  as a whole,
presents fairly in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated  financial statements,  on January 1,
2002, the Company adopted  Statement of Financial  Accounting  Standards No. 142
"Goodwill and Other  Intangible  Assets," (SFAS No. 142) to change its method of
accounting for goodwill and other intangible assets.

                                      146

<PAGE>


As discussed above, the consolidated  financial  statements of the Company as of
December 31,  2001,  and for the two years in the period then ended were audited
by other  auditors  who have  ceased  operations.  The  notes  related  to these
consolidated  financial statements have been revised to include the transitional
disclosures  required  by SFAS No.  142,  which was adopted by the Company as of
January 1, 2002. Our audit  procedures with respect to the disclosures in Note 1
G for 2001 and 2000 included (i) agreeing the previously  reported  earnings for
common stockholders to the previously issued consolidated  financial  statements
and  the   adjustments   to  earnings  for  common   stockholders   representing
amortization  expense  recognized  in those  periods  related to goodwill to the
Company's  underlying  records  obtained from  management,  and (ii) testing the
mathematical  accuracy of the  reconciliation of adjusted net income to reported
earnings for common shareholders, and the related earnings-per-share amounts. In
addition, Note 12 has also been revised. Our auditing procedures with respect to
the  disclosures  in Note 12 for 2001 and 2000 included (i) agreeing the amounts
in the guarantor  and other  subsidiaries  columns to  underlying  consolidating
records obtained from management, (ii) comparing the sum of these columns to the
previously  issued  consolidated  financial  statements,  and (iii)  testing the
mathematical  accuracy of the schedule. In our opinion, the adjustments in Notes
1G and 12 are appropriate and have been properly applied.  However,  we were not
engaged to audit, review, or apply any procedures to the 2001 and 2000 financial
statements  of the  Company  other than with  respect to such  adjustments  and,
accordingly,  we do not express an opinion or any other form of assurance on the
2001 and 2000 financial statements taken as a whole.



DELOITTE & TOUCHE LLP
February 10, 2003
(February 26, 2003, as to Note 16)
New York, New York












                                       147

<PAGE>


REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and Board of Directors of KeySpan Corporation d/b/a/ KeySpan
Energy:

We have audited the  accompanying  Consolidated  Balance Sheet and  Consolidated
Statement of Capitalization of KeySpan  Corporation (a New York corporation) and
subsidiaries  as of  December  31,  2001 and  December  31, 2000 and the related
Consolidated Statements of Income,  Retained Earnings,  Comprehensive Income and
Cash Flows for each of the three years in the period  ended  December  31, 2001.
These financial  statements are the responsibility of the KeySpan  Corporation's
management.  Our  responsibility  is to express  an  opinion on these  financial
statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position and capitalization of KeySpan
Corporation and subsidiaries as of December 31, 2001 and December 31, 2000 and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed in Item 14 is the
responsibility of the KeySpan Corporation's management and is presented for the
purpose of complying with the Securities and Exchange Commission's rules and is
not part of the basic financial statements. This schedule has been subjected to
the auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly states in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.

ARTHUR ANDERSEN LLP
February 4, 2002
New York, New York

Readers of these  consolidated  financial  statements  should be aware that this
report is a copy of a previously issued Arthur Andersen LLP report and that this
report has not been reissued by Arthur  Andersen LLP.  Furthermore,  this report
has not been updated since February 4, 2002 and Arthur Anersen LLP completed its
last  post-audit  review  of  the  December  31,  2001,  consolidated  financial
information on April 29, 2002.

                                       148
<PAGE>


Item 9.  Changes  in  and  Disagreements  with  Accountants  on  Accounting  and
     Financial Disclosure

Arthur Andersen LLP ("Arthur  Andersen") served as KeySpan's  independent public
accountants  since May 1998.  On March 29, 2002,  KeySpan's  Board of Directors,
upon  recommendation  of  the  Audit  Committee,  determined  not to  renew  the
engagement of Arthur  Andersen and appointed  Deloitte & Touche LLP ("Deloitte &
Touche") as  independent  public  accountants.  During the past two fiscal years
through March 29, 2002,  there was no report on the financial  statements of the
Company by either Deloitte & Touche or Arthur Andersen that contained an adverse
opinion  or a  disclaimer  of  opinion,  or  was  qualified  or  modified  as to
uncertainty,  audit scope, or accounting principles.  During the past two fiscal
years through March 29, 2002, there were no disagreements with either Deloitte &
Touche or Arthur  Andersen on any matter of accounting  principles or practices,
financial  statement  disclosure or auditing  scope or procedure  which,  if not
resolved to the  satisfaction  of either  Deloitte & Touche or Arthur  Andersen,
would  have  caused the firm to make  reference  to the  subject  matter of such
disagreements in connection with their respective reports.


                                    Part III

Item 10.   Directors and Executive Officers of the Registrant

A definitive  proxy  statement  will be filed with the SEC on or about March 26,
2003 (the "Proxy Statement"). The information required by this item is set forth
under the caption "Executive Officers of the Company" in Part I hereof and under
the captions  "Proposal 1. Election of Directors" and "Section 16(a)  Beneficial
Ownership  Reporting  Compliance"  contained  in  the  Proxy  Statement,   which
information is incorporated herein by reference thereto.

Item 11.   Executive Compensation

The  information  required by this item set forth under the  captions  "Director
Compensation"  and  "Executive  Compensation"  in  the  Proxy  Statement,  which
information is incorporated herein by reference thereto.

Item 12.   Security Ownership of Certain Beneficial Owners and Management

The information  required by this item is set forth under the captions "Security
Ownership of Management" and "Security  Ownership of Certain  Beneficial Owners"
in the Proxy Statement,  which  information is incorporated  herein by reference
thereto.


                                       149
<PAGE>


Item 13.   Certain Relationships and Related Transactions

The information required by this item is set forth under the caption "Agreements
with Executives,"  "Transactions with Management and Others" and "Involvement in
Certain  Proceedings" in the Proxy Statement,  which information is incorporated
by reference thereto.

Item 14.   Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

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

(b) Changes In Internal Controls

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

Item 15.   Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a)

1.         Financial Statements

The following  consolidated financial statements of KeySpan and its subsidiaries
and report of  independent  accountants  are included in Item 8 and are filed as
part of this Report:

o    Consolidated  Statement of Income for the year ended December 31, 2002, the
     year ended December 31, 2001, and the year ended December 31, 2000
o    Consolidated Statement of Retained Earnings for the year ended December 31,
     2002,  the year ended  December 31, 2001,  and the year ended  December 31,
     2000
o    Consolidated  Balance  Sheet at December  31, 2002 and  December 31, 2001 o
     Consolidated  Statement of Capitalization at December 31, 2002 and December
     31, 2001
o    Consolidated  Statement of Cash Flows for the year ended December 31, 2002,
     the year ended December 31, 2001, and the year ended December 31, 2000
o    Consolidated  Statement of Comprehensive Income for the Year ended December
     31, 2002,  the year ended December 31, 2001 and the year ended December 31,
     2000
o    Notes to Consolidated Financial Statements
o    Report of Independent Public Accountants

2.         Financial Statement Schedules

Consolidated  Schedule of Valuation and  Qualifying  Accounts for the year ended
December 31, 2002, the year ended December 31, 2001, and the year ended December
31, 2000.

All other  schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.


                                      150
<PAGE>

SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
                   Column A                        Column B                Column C             Column D      Column E
                                                                          Additions
-----------------------------------------------------------------------------------------------------------------------
                                                   Balance         Charged to                                Balance at
                                                 at Beginning      costs and                       Net         End of
                Decription                         Period          expenses      Acquisitions   Deductions     Period
-----------------------------------------------------------------------------------------------------------------------

Twelve Months Ended December 31, 2002
-----------------------------------------------
 <S>                                               <C>             <C>           <C>            <C>          <C>
  Deducted from asset accounts:                    $  72,299      $  58,939      $      -       $ 68,209     $  63,029
    Allowance for doubtful accounts

  Additions to liability accounts:
    Reserve for injury and damages                 $  20,880      $  11,984      $      -       $  7,084     $  25,780
    Reserves for environmental expenditures        $ 257,649      $       -      $      -       $ 25,503     $ 232,146

Twelve Months Ended December 31, 2001
-----------------------------------------------
  Deducted from asset accounts:
    Allowance for doubtful accounts                $  48,314      $  66,500      $      -       $ 42,515     $  72,299

  Additions to liability accounts:
    Reserve for injury and damages                 $  40,700      $   7,643      $      -       $ 27,463     $  20,880
    Reserves for environmental expenditures        $ 157,507      $ 115,942      $      -       $ 15,800     $ 257,649

Twelve Months Ended December 31, 2000
-----------------------------------------------
  Deducted from asset accounts:
    Allowance for doubtful accounts                $  20,294      $  26,455      $ 19,208       $ 17,643     $  48,314

  Additions to liability accounts:
    Reserve for injury and damages                 $  36,385      $  20,074      $  3,362       $ 19,121     $  40,700
    Reserves for environmental expenditures        $ 128,011      $       -      $ 42,637       $ 13,141     $ 157,507
-----------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      151
<PAGE>


(b)        Reports on Form 8-K

In our report on Form 8-K dated  October  24,  2002,  we  disclosed  that we had
issued a press  release  concerning,  among other  things,  our earnings for the
third quarter ended September 30, 2002.

In our report on Form 8-K dated  December  12, 2002,  we  disclosed  that we had
issued a press release concerning, among other things, 2003 earnings guidance.

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

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

In our report on Form 8-K dated  January  15,  2003,  we  disclosed  that we had
issued a press release  announcing that our proposed  issuance of  approximately
14,000,000  shares of common  stock  announced  on January  13,  2003,  would be
offered at variable prices.

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

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


(c)        Exhibits

Exhibits  listed  below  which  have been  filed  with the SEC  pursuant  to the
Securities Act of 1933, as amended,  or the Securities  Exchange Act of 1934, as
amended,  and which  were  filed as noted  below,  are  hereby  incorporated  by
reference  and  made a part of this  report  with the  same  effect  as if filed
herewith.

2    Purchase  Agreement by and among Eastern  Enterprises,  Landgrove Corp. and
     KeySpan  Corporation for the acquisition of Midland Enterprises dated as of
     January  23, 2002  (filed as Exhibit 2 to the  Company's  Form 10-K for the
     year ended December 31, 2001)

3.1  Certificate  of  Incorporation  of the Company  effective  April 16,  1998,
     Amendment to  Certificate  of  Incorporation  of the Company  effective May
     26,1998, Amendment to Certificate of Incorporation of the Company effective
     June 1, 1998,  Amendment to the Certificate of Incorporation of the Company
     effective April 7, 1999 and Amendment to the  Certificate of  Incorporation
     of the  Company  effective  May  20,  1999  (filed  as  Exhibit  3.1 to the
     Company's Form 10-Q for the quarterly period ended June 30, 1999)

3.2  ByLaws of the  Company in effect on April 25,  2002,  as amended  (filed as
     Exhibit 3.1 to the Company's Form 10-Q for the quarterly period ended March
     31, 2002)

* Filed herewith
** Management Contract or Compensation Plan


                                       152
<PAGE>


4.1-a     Indenture,  dated as of November 1, 2000, between KeySpan  Corporation
          and the Chase  Manhattan  Bank,  as  Trustee,  with the respect to the
          issuance of Debt  Securities  (filed as Exhibit 4-a to Amendment No. 1
          to Form S-3 Registration  Statement No. 333-43768 and filed as Exhibit
          4-a to the Company's Form 8-K on November 20, 2000)

4.1-b     Form of Note issued in connection with the issuance of the 7.25% notes
          issued on November  20,  2000  (filed as Exhibit 4-b to the  Company's
          Form 8-K on November 20, 2000)

4.1-c     Form of Note  issued in  connection  with the  issuance  of the 7.625%
          notes  issued  on  November  20,  2000  (filed as  Exhibit  4-c to the
          Company's Form 8-K on November 20, 2000)

4.1-d     Form of Note issued in connection  with the issuance of the 8.0% notes
          issued on November  20,  2000  (filed as Exhibit 4-d to the  Company's
          Form 8-K on November 20, 2000)

4.1-e     Form of Note issued in connection with the issuance of the 6.15% notes
          issued on May 24, 2001 (filed as Exhibit 4 to the  Company's  Form 8-K
          on May 24, 2001)

4.2-a     Indenture,  dated  December 1, 1999,  between  KeySpan and KeySpan Gas
          East  Corporation,  the Registrants,  and the Chase Manhattan Bank, as
          Trustee,  with respect to the issuance of Medium-Term Notes, Series A,
          (filed as Exhibit 4-a to Amendment  No. 1 to the Company's and KeySpan
          Gas East Corporation's Form S-3 Registration Statement No. 333-92003)

4.2-b     Form of  Medium-Term  Note issued in  connection  with the issuance of
          KeySpan Gas East  Corporation  7 7/8% notes issued on February 1, 2000
          (filed as Exhibit 4 to the Company's Form 8-K on February 1, 2000)

4.2-c     Form of  Medium-Term  Note issued in  connection  with the issuance of
          KeySpan  Gas East  Corporation  6.9% notes  issued on January 19, 2001
          (filed as Exhibit  4.3 to the  Company's  Form 10-K for the year ended
          December 31, 2000)

4.3-a     Participation Agreements dated as of February 1, 1989, between NYSERDA
          and The Brooklyn Union Gas Company relating to the Adjustable Rate Gas
          Facilities  Revenue  Bonds  ("GFRBs")  Series  1989A and Series  1989B
          (filed as Exhibit 4 to The Brooklyn  Union Gas Company's Form 10-K for
          the year ended September 30, 1989)

4.3-b     Indenture  of Trust,  dated  February  1, 1989,  between  NYSERDA  and
          Manufacturers  Hanover  Trust  Company,  as  Trustee,  relating to the
          Adjustable  Rate GFRBs  Series  1989A and 1989B (filed as Exhibit 4 to
          the  Brooklyn  Union  Gas  Company's  Form  10-K  for the  year  ended
          September 30, 1989)

4.3-c     First Supplemental  Participation Agreement dated as of May 1, 1992 to
          Participation Agreement dated February 1, 1989 between NYSERDA and The
          Brooklyn Union Gas Company  relating to Adjustable Rate GFRBs,  Series
          1989A & B (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form
          10-K for the year ended September 30, 1992)

4.3-d     First  Supplemental  Trust  Indenture dated as of May 1, 1992 to Trust
          Indenture  dated  February 1, 1989 between  NYSERDA and  Manufacturers
          Hanover Trust Company, as Trustee,  relating to Adjustable Rate GFRBs,
          Series  1989A & B  (filed  as  Exhibit  4 to The  Brooklyn  Union  Gas
          Company's Form 10-K for the year ended September 30, 1992)

* Filed herewith
** Management Contract or Compensation Plan

                                       153
<PAGE>

4.4-a     Participation Agreement, dated as of July 1, 1991, between NYSERDA and
          The Brooklyn Union Gas Company  relating to the GFRBs Series 1991A and
          1991B (filed as Exhibit 4 to The  Brooklyn  Union Gas  Company's  Form
          10-K for the year ended September 30, 1991)

4.4-b     Indenture  of Trust,  dated as of July 1, 1991,  between  NYSERDA  and
          Manufacturers Hanover Trust Company, as Trustee, relating to the GFRBs
          Series 1991A and 1991B  (filed as Exhibit 4 to The Brooklyn  Union Gas
          Company's Form 10-K for the year ended September 30, 1991)

4.5-a     Participation Agreement, dated as of July 1, 1992, between NYSERDA and
          The Brooklyn Union Gas Company  relating to the GFRBs Series 1993A and
          1993B (filed as Exhibit 4 to The  Brooklyn  Union Gas  Company's  Form
          10-K for the year ended September 30, 1992)


4.5-b     Indenture  of Trust,  dated as of July 1, 1992,  between  NYSERDA  and
          Chemical  Bank,  as Trustee,  relating to the GFRBs  Series  1993A and
          1993B (filed as Exhibit 4 to The Brooklyn  Union Gas Company Form 10-K
          for the year ended September 30, 1992)


4.6-a     First Supplemental Participation Agreement dated as of July 1, 1993 to
          Participation  Agreement dated as of June 1, 1990, between NYSERDA and
          The  Brooklyn  Union Gas Company  relating to GFRBs Series C (filed as
          Exhibit 4 to The Brooklyn  Union Gas Company's  Form 10-K for the year
          ended September 30, 1993)

4.6-b     First  Supplemental  Trust Indenture dated as of July 1, 1993 to Trust
          Indenture  dated as of June 1, 1990 between NYSERDA and Chemical Bank,
          as  Trustee,  relating  to GFRBs  Series C (filed as  Exhibit 4 to The
          Brooklyn  Union Gas Company's  Form 10-K for the year ended  September
          30, 1993)

4.7-a     Participation  Agreement,  dated July 15,  1993,  between  NYSERDA and
          Chemical  Bank as Trustee,  relating to the GFRBs  Series D-1 1993 and
          Series  D-2  1993  (filed  as  Exhibit  4 to The  Brooklyn  Union  Gas
          Company's Form S-8 Registration Statement No. 33-66182)


4.7-b     Indenture of Trust,  dated July 15, 1993, between NYSERDA and Chemical
          Bank as Trustee,  relating  to the GFRBs  Series D-1 1993 and D-2 1993
          (filed as  Exhibit 4 to The  Brooklyn  Union  Gas  Company's  Form S-8
          Registration Statement No. 33-66182)

4.8-a     Participation  Agreement,  dated January 1, 1996,  between NYSERDA and
          The Brooklyn Union Gas Company relating to GFRBs Series 1996 (filed as
          Exhibit 4 to The Brooklyn  Union Gas Company's  Form 10-K for the year
          ended September 30, 1996)


4.8-b     Indenture  of Trust,  dated  January  1,  1996,  between  NYSERDA  and
          Chemical  Bank,  as Trustee,  relating to GFRBs  Series 1996 (filed as
          Exhibit 4 to The Brooklyn  Union Gas Company's  Form 10-K for the year
          ended September 30, 1996)


4.9-a     Participation Agreement,  dated as of January 1, 1997, between NYSERDA
          and The  Brooklyn  Union Gas  Company  relating to GFRBs 1997 Series A
          (filed as Exhibit 4 to The Brooklyn  Union Gas Company's Form 10-K for
          the year ended September 30, 1997)


4.9-b     Indenture of Trust,  dated January 1, 1997,  between NYSERDA and Chase
          Manhattan Bank, as Trustee,  relating to GFRBs 1997 Series A (filed as
          Exhibit 4 to The Brooklyn  Union Gas Company's  Form 10-K for the year
          ended September 30, 1997)

* Filed herewith
** Management Contract or Compensation Plan


                                       154
<PAGE>


4.9-c     Supplemental  Trust  Indenture,  dated as of January  1, 2000,  by and
          between  New York  State  NYSERDA  and The Chase  Manhattan  Bank,  as
          Trustee, relating to the GFRBs 1997 Series A (filed as Exhibit 4.11 to
          the Company's Form 10-K for the year ended December 31, 1999)


4.10-a    Participation  Agreement  dated as of  December 1, 1997 by and between
          NYSERDA and Long Island Lighting  Company  relating to the 1997 EFRBs,
          Series A (filed as Exhibit  10(a) to the  Company's  Form 10-Q for the
          quarterly period ended September 30, 1998)


4.10-b    Indenture of Trust dated as of December 1, 1997 by and between NYSERDA
          and The  Chase  Manhattan  Bank,  as  Trustee,  relating  to the  1997
          Electric Facilities Revenue Bonds (EFRBs),  Series A (filed as Exhibit
          10(a) to the  Company's  Form  10-Q  for the  quarterly  period  ended
          September 30, 1998)

4.11-a    Participation  Agreement,  dated as of October 1, 1999, by and between
          NYSERDA  and KeySpan  Generation  LLC  relating to the 1999  Pollution
          Control  Refunding  Revenue Bonds,  Series A (filed as Exhibit 4.10 to
          the Company's Form 10-K for the year ended December 31, 1999)


4.11-b    Trust  Indenture,  dated as of October 1, 1999, by and between NYSERDA
          and The  Chase  Manhattan  Bank,  as  Trustee,  relating  to the  1999
          Pollution Control Refunding Revenue Bonds,  Series A (filed as Exhibit
          4.10 to the Company's Form 10-K for the year ended December 31, 1999)


4.12      Indenture  dated as of December 1, 1989 between Boston Gas Company and
          The Bank of New York,  Trustee  (Filed as  Exhibit  4.2 to Boston  Gas
          Company's Form S-3 (File No. 33-31869).


4.13      Agreement of  Registration,  Appointment  and  Acceptance  dated as of
          November 18, 1992 among  Boston Gas  Company,  The Bank of New York as
          Resigning Trustee,  and The First National Bank of Boston as Successor
          Trustee. (Filed as an exhibit to Boston Gas Company's S-3 Registration
          S (File No. 33-31869))


4.14      Second Amended and Restated First Mortgage  Indenture for Colonial Gas
          Company  dated as of June 1, 1992  (filed as Exhibit  4(b) to Colonial
          Gas Company's Form 10-Q for the quarter ended June 30, 1992)

4.15      First Supplemental Indenture for Colonial Gas Company dated as of June
          15, 1992 (filed as Exhibit  4(c) to Colonial Gas  Company's  Form 10-Q
          for the quarter ended June 30, 1992)

4.16      Second  Supplemental  Indenture  for Colonial Gas Company  dated as of
          September  27, 1995 (filed as Exhibit 4(c) to Colonial  Gas  Company's
          Form 10-K for the fiscal year ended December 31, 1995)


4.17      Amendment to Second  Supplemental  Indenture  for Colonial Gas Company
          dated as of October 12, 1995  (filed as Exhibit  4(d) to Colonial  Gas
          Company's Form 10-K for the fiscal year ended December 31, 1995)

4.18      Third  Supplemental  Indenture  for Colonial  Gas Company  dated as of
          December  15, 1995 (filed as Exhibit  4(f) to Colonial  Gas  Company's
          Form S-3 Registration Statement dated January 5, 1998)

4.19      Fourth  Supplemental  Indenture  for Colonial Gas Company  dated as of
          March 1, 1998 (filed as Exhibit  4(l) to Colonial Gas  Company's  Form
          10-Q for the quarter ended March 31, 1998)

* Filed herewith
** Management Contract or Compensation Plan


                                       155
<PAGE>

4.20      Trust Agreement dated as of June 22, 1990 between Colonial Gas Company
          (as Trustor)  and Shawmut  Bank,  N.A. (as Trustee)  (filed as Exhibit
          10(d) to Colonial  Gas  Company's  Form 10-Q for the period ended June
          30, 1990)

4.21      Gas Service,  Inc. General and Refunding Mortgage Indenture,  dated as
          of June 30, 1987, as amended and supplemented by a First  Supplemental
          Indenture,  dated as of October 1, 1988, and by a Second  Supplemental
          Indenture,  dated as of  August  31,  1989  (filed as  Exhibit  4.1 to
          EnergyNorth,  Inc.'s Form 10-K for the fiscal year ended September 30,
          1989 (File No. 0-11035)

4.22      Third  Supplemental  Indenture,  dated as of September 1, 1990, to Gas
          Service,  Inc. General and Refunding Mortgage  Indenture,  dated as of
          June 30, 1987 (filed as Exhibit 4.2 to  EnergyNorth,  Inc.'s Form 10-K
          for the fiscal year ended September 30, 1990 (File No. 0-11035)

4.23      Fourth  Supplemental  Indenture,  dated as of January 10, 1992, to Gas
          Service,  Inc. General and Refunding Mortgage  Indenture,  dated as of
          June 30, 1987 (filed as Exhibit 4.3 of  EnergyNorth,  Inc.'s Form 10-K
          for the fiscal year ended September 30, 1992 (File No. 0-11035)

4.24      Fifth  Supplemental  Indenture,  dated as of February 1, 1995,  to Gas
          Service,  Inc. General and Refunding Mortgage  Indenture,  dated as of
          June 30, 1987 (filed as Exhibit 4.4 to  EnergyNorth,  Inc.'s Form 10-K
          for the fiscal year ended September 30, 1996 (File No. 1-11441)

4.25      Sixth Supplemental  Indenture,  dated as of September 15, 1997, to Gas
          Service,  Inc. General and Refunding Mortgage  Indenture,  dated as of
          June 30, 1987 (filed as Exhibit 4.5 to EnergyNorth Natural Gas, Inc.'s
          Amendment No. 1 to Registration  Statement on Form S-1, No. 333-32949,
          dated September 10, 1997)


4.26      Indenture  dated as of June 1,  1986  between  Essex Gas  Company  and
          Centerre Trust Company of St. Louis, Trustee.  (Filed as an Exhibit to
          Essex Gas Company's Registration Statement on Form S-2, filed June 19,
          1986, File No. 33-6597).

4.27      Twelfth  Supplemental  Indenture dated as of December 1, 1990, between
          Essex Gas Company and Centerre  Trust Company of St.  Louis,  Trustee,
          providing for a 10.10 percent Series due 2020.  (Filed as Exhibit 4-14
          to Essex Gas Company's  Form 10-Q for the quarter  ended  February 28,
          1991).

4.28      Fifteenth Supplemental Indenture dated as of December 1, 1996, between
          Essex Gas Company and Centerre  Trust Company of St.  Louis,  Trustee,
          providing for a 7.28 percent Series due 2017. (Filed as Exhibit 4.5 to
          the Essex Gas Company's  Form 10-Q for the quarter ended  February 28,
          1997).

4.29      Bond Purchase  Agreement dated December 1, 1990, between Allstate Life
          Insurance Company of New York, and Essex County Gas Company. (Filed as
          an Exhibit to Company's  Form 10-Q for the quarter ended  February 28,
          1991).

4.30-a    Letter of Credit and Reimbursement Agreement,  dated as of December 1,
          2000, by and between KeySpan Generation LLC and National  Westminister
          Bank PLC relating to the Electric  Facilities  Revenue Bonds ("EFRBs")
          Series 1997A (filed as Exhibit 4.10 to the Company's Form 10-K for the
          year ended December 31, 2000).

4.30-b    Extension  Agreement,  dated as of November  20, 2002 by and between
          KeySpan Generation LLC and National  Westmnister Bank PLC, relating to
          the Letter of Credit and Reimbursement Agreement, dated as of December
          1, 2000 (filed as Exhibit  4.30-b to the  Company's  Form 10-K for the
          year ended December 31, 2002)

* Filed herewith
** Management Contract or Compensation Plan


                                       156
<PAGE>


4.31      Indenture,  dated as of March 2, 1998, between The Houston Exploration
          Company and The Bank of New York,  as Trustee,  with  respect to the 8
          5/8%  SENIOR  Subordinated  Notes Due 2008  (including  form of 8 5/8%
          SENIOR  Subordinated  Note Due  2008)  (filed  as  Exhibit  4.1 to The
          Houston Exploration Company's  Registration Statement on Form S-4 (No.
          333-50235))

10.1      Amendment,  Assignment and Assumption  Agreement dated as of September
          29,  1997 by and among The  Brooklyn  Union Gas  Company,  Long Island
          Lighting Company and KeySpan Energy  Corporation (filed as Exhibit 2.5
          to Schedule 13D by Long Island Lighting Company on October 24, 1997)

10.2      Agreement and Plan of Merger dated as of June 26, 1997 by and among BL
          Holding  Corp.,  Long  Island  Lighting  Company,  Long  Island  Power
          Authority and LIPA Acquisition Corp. (filed as Annex D to Registration
          Statement on Form S-4, No. 333-30353 on June 30, 1997)

10.3      Agreement of Lease between  Forest City Jay Street  Associates and The
          Brooklyn  Union Gas  Company  dated  September  15,  1988 (filed as an
          exhibit to The  Brooklyn  Union Gas  Company's  Form 10-K for the year
          ended September 30, 1996)

10.4-a    Management  Services Agreement between Long Island Power Authority and
          Long Island Lighting Company dated as of June 26, 1997 (filed as Annex
          D to Registration  Statement on Form S-4, No.  333-30353,  on June 30,
          1997)

10.4-b    Amendment  dated  as of  March  29,  2002  to  Management  Services
          Agreement  between Long Island Lighting Company d/b/a LIPA and KeySpan
          Electric  Services  LLC dated as of June 26,  1997  (filed as  Exhibit
          10.4-b to the  Company's  Form 10-K for the year  ended  December  31,
          2002)

10.5      Power Supply  Agreement  between Long Island Lighting Company and Long
          Island Power  Authority dated as of June 26, 1997 (filed as Annex D to
          Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)

10.6-a    Energy  Management  Agreement between Long Island Lighting Company and
          Long Island Power  Authority dated as of June 26, 1997 (filed as Annex
          D to Registration  Statement on Form S-4, No.  333-30353,  on June 30,
          1997)

10.6-b    Amendment dated as of March 29, 2002 to Energy Management  Agreement
          between Long Island  Lighting  Company  d/b/a LIPA and KeySpan  Energy
          Trading  Services  LLC dated as of June 26,  1997  (filed  as  Exhibit
          10.6-b to the  Company's  Form 10-K for the year  ended  December  31,
          2002)

10.7-a    Generation  Purchase  Rights  Agreement  between Long Island  Lighting
          Company  and Long  Island  Power  Authority  dated as of June 26, 1997
          (filed as Exhibit  10.17 to the  Company's  Annual Report on Form 10-K
          for the year ended December 31, 2001)

10.7-b    Amendment  dated as of March 29,  2002 to  Generation  Purchase  Right
          Agreement  by and  between  KeySpan  Corporation  as Seller,  and Long
          Island Lighting Company d/b/a LIPA as Buyer, dated as of June 26, 1997
          (filed as Exhibit 10.1 to the Company's  Quarterly Report on Form 10-Q
          for the quarterly period ended March 31, 2002)

10.8**    Employment  Agreement  dated  September 10, 1998,  between KeySpan and
          Robert B. Catell (filed as Exhibit (10)(b) to the Company's  Quarterly
          Report on Form 10-Q for the quarterly period ended September 30, 1998)

10.9**    First  Amendment  dated as of February  24,  2000,  to the  Employment
          Agreement  dated  September  10, 1998,  between  KeySpan and Robert B.
          Catell  (filed as Exhibit  10.12-a to the  Company's  Annual Report on
          Form 10-K for the year ended December 31, 2000)

* Filed herewith
** Management Contract or Compensation Plan


                                       157
<PAGE>

10.10**   Second  Amendment  dated  as of  June  26,  2002,  to  the  Employment
          Agreement  dated  September  10, 1998,  between  KeySpan and Robert B.
          Catell  (filed as Exhibit 10.1 to the  Company's  Quarterly  Report on
          Form 10-Q for the quarterly period ended September 30, 2002)

10.11     Supplemental  Retirement  Agreement  dated  January  1,  2002  between
          KeySpan and Gerald  Luterman  (filed as Exhibit 10.11 to the Company's
          Form 10-K for the year ended December 31, 2002)

10.12     Supplemental  Retirement  Agreement  dated  January  1,  2002  between
          KeySpan  and  Steven  L.  Zelkowitz  (filed  as  Exhibit  10.12 to the
          Company's Form 10-K for the year ended December 31, 2002)

10.13     Supplemental  Retirement  Agreement  dated  January  1,  2002  between
          KeySpan and David J. Manning  (filed as Exhibit 10.13 to the Company's
          Form 10-K for the year ended December 31, 2002)

10.14     Supplemental  Retirement  Agreement  dated  January  1,  2002  between
          KeySpan and Neil Nichols (filed as Exhibit 10.14 to the Company's Form
          10-K for the year ended December 31, 2002)

10.15     Supplemental  Retirement  Agreement  dated  January  1,  2002  between
          KeySpan and Elaine  Weinstein (filed as Exhibit 10.15 to the Company's
          Form 10-K for the year ended December 31, 2002)

10.16**   Amended Directors' Deferred  Compensation Plan (filed as Exhibit 10.27
          to the Company's Form 10-K for the year ended December 31, 2001)

10.17**   Officers' Deferred Stock Unit Plan of KeySpan Corporation (filed as
          Exhibit 10.17 to the Company's  Form 10-K for the year ended  December
          31, 2002)

10.18**   Officers' Deferred Stock Unit Plan KeySpan Services, Inc. (filed as
          Exhibit 10.18 to the Company's  Form 10-K for the year ended  December
          31, 2002)

10.19**   Corporate Annual Incentive Compensation and Gainsharing Plan (filed as
          Exhibit 10.20 to the Company's  Form 10-K for the year ended  December
          31, 2000)


10.20**   Senior  Executive  Change of Control  Severance  Plan  effective as of
          October 30, 1998 (filed as Exhibit  10.20 to the  Company's  Form 10-K
          for the year ended December 31, 1998)

10.21**   KeySpan's  Amended Long Term Performance  Incentive  Compensation Plan
          (filed as Exhibit A to the Company's 2001 Proxy Statement on March 23,
          2001)


10.22     Rights  Agreement  dated March 30,  1999,  between the KeySpan and the
          Rights Agent (filed as Exhibit 4 to the  Company's  Form 8-K, on March
          30, 1999)


10.23     Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for
          Ravenswood  for  Ravenswood  Generating  Plants and Gas Turbines dated
          January 28, 1999, between the KeySpan and Consolidated  Edison Company
          of New York,  Inc.  (filed as Exhibit 10(a) to the Company's Form 10-Q
          for the quarterly period ended March 31, 1999)


10.24     Lease Agreement dated June 9, 1999,  between  KeySpan-Ravenswood,  LLC
          and LIC  Funding,  Limited  Partnership  (filed as Exhibit 10.2 to the
          Company's Form 10-Q for the quarterly period ended June 30, 1999)

10.25     First Amendment to the Lease between  KeySpan-Ravenswood,  LLC and LIC
          Funding,  Limited  Partnership,  dated as of June 27,  2002  (filed as
          Exhibit 10.25 to the Company's  Form 10-K for the year ended  December
          31, 2002)


10.26     Guaranty  dated June 9, 1999,  from  KeySpan in favor of LIC  Funding,
          Limited  Partnership (filed as Exhibit 10.1 to the Company's Form 10-Q
          for the quarterly period ended June 30, 1999)

10.27     Purchase   Agreement  by  and  among  Duke  Energy  Gas   Transmission
          Corporation,  Algonquin Energy,  Inc., KeySpan LNG GP, LLC and KeySpan
          LNG LP, dated as of December  12, 2002 (filed as Exhibit  10.27 to the
          Company's Form 10-K for the year ended December 31, 2002)

* Filed herewith
** Management Contract or Compensation Plan


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<PAGE>

10.28     Restated Exploration Agreement between The Houston Exploration Company
          and KeySpan Exploration and Production,  L.L.C.,  dated June 30, 2000,
          (filed as Exhibit 10.1 to The Houston Exploration  Company's Quarterly
          Report on Form 10-Q for the quarter ended September 30, 2000, File No.
          001-11899)


10.29     Revolving Credit Facility between The Houston  Exploration Company and
          Wachovia   Bank,   National   Association,   as   issuing   bank   and
          administrative  agent,  Bank of Nova Scotia and Fleet National Bank as
          co-syndication  agents and BNP  Paribas as  documentation  agent dated
          July 15,  2002  (filed  as  Exhibit  10.1 to The  Houston  Exploration
          Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
          2002, File No. 001-11899)

10.30-a   Credit Agreement among KeySpan Energy  Development Co. several Lenders
          and the Royal Bank of Canada,  as Agent, for  $125,000,000  (Canadian)
          Credit Facility,  dated as of October 13, 2000 (filed as Exhibit 10.10
          to the  Company's  Annual  Report  on Form  10-K  for the  year  ended
          December 31, 2001)

10.30-b   Consent,   Waiver  and  Amending   Agreement   among  KeySpan   Energy
          Development  Co.,  several  Lenders  and the Royal Bank of Canada,  as
          Agent, for the $125,000,000  (Canadian)  Credit Facility,  dated as of
          December  22, 2000  (filed as Exhibit  10.11 to the  Company's  Annual
          Report on Form 10-K for the year ended December 31, 2001)

10.30-c   Second  Amending  Agreement  among  KeySpan  Energy  Development  Co.,
          several  Lenders  and the Royal  Bank of  Canada,  as  Agent,  for the
          $125,000,000 (Canadian) Credit Facility,  dated as of October 12, 2001
          (filed as Exhibit  10.12 to the  Company's  Annual Report on Form 10-K
          for the year ended December 31, 2001)

10.30-d   Extendible  Revolving  Credit Facility  Amended and Restated Credit
          Agreement  among  KeySpan  Energy   Development  Co.,   National  Bank
          Financial,  ATB  Financial  and Certain  Financial  Institutions  with
          National  Bank of  Canada,  dated as of  January  24,  2003  (filed as
          Exhibit 10.30-d to the Company's Form 10-K for the year ended December
          31, 2002)

10.31-a   Credit Agreement among KeySpan Energy Development Co.,  Borrower,  the
          Several Lenders' and Royal Bank of Canada, Administrative Agent, dated
          July 29, 1999 (filed as Exhibit 10.37-a to the Company's Annual Report
          on Form 10-K for the year ended December 31, 2001)

10.31-b   First  Amending  Agreement  dated as of October 13, 2000 to the Credit
          Agreement among KeySpan Energy Development Co., Borrower,  the Several
          Lenders' and Royal Bank of Canada, Administrative Agent dated July 29,
          1999 (filed as Exhibit 10.37-b to the Company's  Annual Report on Form
          10-K for the year ended December 31, 2001)

10.31-c   Second Amending  Agreement dated as of December 15, 2000 to the Credit
          Agreement among KeySpan Energy Development Co., Borrower,  the Several
          Lenders' and Royal Bank of Canada, Administrative Agent dated July 29,
          1999 (filed as Exhibit 10.37-c to the Company's  Annual Report on Form
          10-K for the year ended December 31, 2001)

10.31-d   Third  Amending  Agreement  dated as of  December  20,  2002 to the
          Credit Agreement among KeySpan Energy Development Co.,  Borrower,  the
          Several Lenders' and Royal Bank of Canada,  Administrative Agent dated
          July 29, 1999 (filed as Exhibit 10.31-d to the Company's Form 10-K for
          the year ended December 31, 2002)

10.32     Guarantee  Agreement  by KeySpan  Corporation  in favor of the Several
          Lenders to KeySpan  Energy  Development  Co. dated as of July 29, 1999
          (filed as Exhibit  10.38 to the  Company's  Annual Report on Form 10-K
          for the year ended December 31, 2001)

* Filed herewith
** Management Contract or Compensation Plan


                                       159
<PAGE>

10.33     Credit Agreement among KeySpan  Corporation,  the several Lenders, ABN
          AMRO Bank, N.V. and Citibank, N.A., as Co-Syndication Agents, The Bank
          of New York and The Royal Bank of Scotland  PLC,  as  Co-Documentation
          Agents,  and J.P. Morgan Chase Bank, as Administrative  Agent for $1.3
          billion,  dated  as of July  9,  2002  (filed  as  Exhibit  4.1 to the
          Company's Form 10-Q for the quarterly period ended June 30, 2002)


12        Computation in support of ratio of earnings to fixed charges and ratio
          of combined  fixed charges and  dividends  (filed as Exhibit 12 to the
          Company's Form 10-K for the year ended December 31, 2002)

21        Subsidiaries  of the Registrant  (filed as Exhibit 21 to the Company's
          Form 10-K for the year ended December 31, 2002)

23.1*     Consent of Deloitte & Touche LLP, Independent Auditors

23.2*     Consent  of  Netherland,   Sewell  &  Associates,   Inc.,  Independent
          Petroleum Consultants

23.3*     Consent of Miller and Lents, Ltd., Independent Petroleum Consultants

24.1      Power of Attorney executed by Robert B. Catell on March 6, 2003 (filed
          as Exhibit 24.1 to the Company's Form 10-K for the year ended December
          31, 2002)

24.2      Power of Attorney  executed by Andrea S.  Christensen on March 6, 2003
          (filed as Exhibit 24.2 to the  Company's  Form 10-K for the year ended
          December 31, 2002)

24.3      Power of  Attorney  executed  by  Donald H.  Elliott  on March 6, 2003
          (filed as Exhibit 24.3 to the  Company's  Form 10-K for the year ended
          December 31, 2002)

24.4      Power of Attorney  executed by Alan H. Fishman on March 6, 2003 (filed
          as Exhibit 24.4 to the Company's Form 10-K for the year ended December
          31, 2002)

24.5      Power of  Attorney  executed by J. Atwood Ives on March 6, 2003 (filed
          as Exhibit 24.5 to the Company's Form 10-K for the year ended December
          31, 2002)

24.6      Power of  Attorney  executed by James R. Jones on March 6, 2003 (filed
          as Exhibit 24.6 to the Company's Form 10-K for the year ended December
          31, 2002)

24.7      Power of Attorney executed by James L. Larocca on March 6, 2003 (filed
          as Exhibit 24.7 to the Company's Form 10-K for the year ended December
          31, 2002)

24.8      Power of  Attorney  executed  by Stephen  W.  McKessy on March 6, 2003
          (filed as Exhibit 24.8 to the  Company's  Form 10-K for the year ended
          December 31, 2002)

24.9      Power of Attorney executed by Edward D. Miller on March 6, 2003 (filed
          as Exhibit 24.9 to the Company's Form 10-K for the year ended December
          31, 2002)

24.10     Power of  Attorney  executed by Edward  Travaglianti  on March 6, 2003
          (filed as Exhibit 24.10 to the Company's  Form 10-K for the year ended
          December 31, 2002)

24.11     Certified   copy  of  the   Resolution   of  the  Board  of  Directors
          authorizing signatures pursuant to power of attorney (filed as Exhibit
          24.11 to the Company's Form 10-K for the year ended December 31, 2002)

99.1*     Certification  of the Chief  Executive  Officer  pursuant  to 18 U.S.C
          1350,as adopted pursuant to Section 906 of the  Sarbanes-Oxley  Act of
          2002 dated March 6, 2003

99.2*     Certification  of the Chief  Financial  Officer  pursuant  to 18 U.S.C
          1350,as adopted pursuant to Section 906 of the  Sarbanes-Oxley  Act of
          2002 dated March 6, 2003

99.3*     Certification  of the Chief  Executive  Officer  pursuant  to 18 U.S.C
          1350,as adopted pursuant to Section 906 of the  Sarbanes-Oxley  Act of
          2002 dated July 24, 2003

99.4*     Certification  of the Chief  Financial  Officer  pursuant  to 18 U.S.C
          1350,as adopted pursuant to Section 906 of the  Sarbanes-Oxley  Act of
          2002 dated July 24, 2003

* Filed herewith
** Management Contract or Compensation Plan


                                       160
<PAGE>





                                   SIGNATURES

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


                                    KEYSPAN CORPORATION



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



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



                                       161
<PAGE>



                     CHIEF EXECUTIVE OFFICER'S CERTIFICATION

I, Robert B Catell, certify that:

1. I have reviewed this annual report on Form 10-K of KeySpan Corporation;

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

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

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

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

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

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

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

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

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

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

Date:                July 24, 2003          /s/ Robert B. Catell
                                            ------------------------------
                                            Robert B. Catell
                                            Chairman of the Board of Directors
                                            and Chief Executive Officer




                                       162
<PAGE>




                     CHIEF FINANCIAL OFFICER'S CERTIFICATION

I, Gerald Luterman, certify that:

1. I have reviewed this annual report on Form 10-K of KeySpan Corporation;

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

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

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

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

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

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

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

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

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

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

Date:      July 24, 2003                     /s/ Gerald Luterman
                                             -----------------------------
                                             Gerald Luterman
                                             Executive Vice President
                                             and Chief Financial Officer



                                       163
<PAGE>




Pursuant to the requirements of the Securities Exchange Act of 1934, as amended,
this report has been signed by the following persons on behalf of the registrant
and in the capacities indicated.

           *
--------------------
Andrea S. Christensen         Director


           *
--------------------
Donald H. Elliott             Director


           *
--------------------
Alan H. Fishman               Director


           *
--------------------
J. Atwood Ives Director


           *
--------------------
James R. Jones                Director


           *
--------------------
James L. Larocca              Director


           *
--------------------
Stephen W. McKessy             Director


           *
--------------------
Edward D. Miller               Director


           *
--------------------
Edward Travaglianti            Director


By:/s/ Gerald Luterman
    Attorney-in-Fact

* Such  signature has been affixed  pursuant to a Power of Attorney  filed as an
exhibit hereto and incorporated herein by reference thereto.




                                       164