UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

[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 fiscal year ended December 31, 2003

                         Commission File Number 1-14161

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

         NEW YORK                                          11-3431358
(State or other jurisdiction                (I.R.S. employer identification no.)
 of 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. X Yes __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. X

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

As of June 30,  2003,  the  aggregate  market  value of the common stock held by
non-affiliates  (157,824,519  shares) of the registrant was $5,594,879,198 based
on the closing price of the New York Stock  Exchange on such date, of $35.45 per
share.  For purposes of this  computation,  all  officers  and  directors of the
registrant are deemed to be affiliates.

As of March 1, 2004,  there were  159,844,530  shares of common stock,  $.01 par
value, outstanding.

                      DOCUMENTS INCORPORATED BY REFERENCE
Proxy  Statement  dated on or about March 25, 2004 is  incorporated by reference
into Part III hereof.

<PAGE>


                               KEYSPAN CORPORATION
                               INDEX TO FORM 10-K
<TABLE>
<CAPTION>
                                                                                                                               Page
                                                                                                                               ----
                                     PART I
                                     ------
   <S>                                                                                                                         <C>
    Item 1.             Description of the Business...............................................................................1
    Item 2.             Properties...............................................................................................33
    Item 3.             Legal Proceedings........................................................................................34
    Item 4.             Submission of Matters to a Vote of Security Holders......................................................34

                                     PART II
                                     -------
    Item 5.             Market for Registrant's Common Equity and Related Stockholder Matters....................................34
    Item 6.             Selected Financial Data..................................................................................36
    Item 7.             Management's Discussion and Analysis of Financial Condition and Results of Operations....................37
    Item 7A.            Quantitative and Qualitative Disclosures About Market Risk...............................................85
    Item 8.             Financial Statements and Supplementary Data..............................................................87
    Notes to the Consolidated Financial Statements...............................................................................93
    Note 1.             Summary of Significant Accounting Policies...............................................................93
    Note 2.             Business Segments.......................................................................................111
    Note 3.             Income Tax..............................................................................................115
    Note 4.             Postretirement Benefits.................................................................................117
    Note 5.             Capital Stock...........................................................................................122
    Note 6.             Long-Term Debt..........................................................................................123
    Note 7.             Contractual Obligations, Financial Guarantees and Contingencies.........................................129
    Note 8.             Hedging, Derivative Financial Instruments and Fair Values...............................................139
    Note 9.             Discontinued Operations.................................................................................144
    Note 10.            Roy Kay Operations......................................................................................145
    Note 11.            Class Action Settlement.................................................................................146
    Note 12.            KeySpan Gas East Corporation Summary Financial Data.....................................................146
    Note 13.            Workforce Reduction Programs............................................................................152
    Note 14.            Shareholder Rights Plan.................................................................................152
    Note 15.            Subsequent Events.......................................................................................153
    Note 16.            Supplemental Gas and Oil Disclosures (Unaudited)........................................................153
    Note 17.            Summary of Quarterly Information (Unaudited)............................................................158
    INDEPENDENT AUDITORS' REPORT................................................................................................159
    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS....................................................................................161
    Item 9.             Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................162
    Item 9A.            Controls and Procedures.................................................................................162

                                    PART III
    Item 10.            Directors and Executive Officers of the Registrant......................................................162
    Item 11.            Executive Compensation..................................................................................163
    Item 12.            Security Ownership of Certain Beneficial Owners and Management..........................................163
    Item 13.            Certain Relationships and Related Transactions..........................................................163
    Item 14.            Principal Accounting Fees and Services..................................................................163
    Item 15.            Exhibits, Financial Statement Schedules and Reports on Form 8-K.........................................163
</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, 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  generating  capacity and, to the extent required,
energy conversion  services for LIPA from our  approximately  4,200 megawatts of
generating  facilities located on Long Island; and manage fuel supplies for LIPA
to fuel our 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, as well as the 250 megawatt  expansion  unit at
Ravenswood expected to be completed within the next few months.

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

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  pipeline
activities in the United Kingdom.


                                       1
<PAGE>


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 core businesses.
We also  continue to explore  the  monetization  of some or all of our  non-core
assets in the Energy Investments segment.

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 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;

-    the resolution of certain disputes with LIPA concerning each party's rights
     and obligations under various agreements;

-    retention of key personnel;


                                       2
<PAGE>


-    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 and conduct operations;

-    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

-    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 the 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.

KeySpan has adopted a Code of Ethics  applicable to its Chief Executive  Officer
and Senior  Financial  Officers,  and has revised its Ethical  Business  Conduct
Statement applicable to all directors,  officers and employees of the Company in
each case as required by recently adopted rules and regulations.

KeySpan's  Code  of  Ethics,  Ethical  Business  Conduct  Statement,   Corporate
Governance  Guidelines and Committee  Charters can each be found on the Investor
Relations  section  of  KeySpan's  website   (http://www.keyspanenergy.com)  and
provide  information  on the  framework  and high  standards  set by the Company
relating to its corporate governance and business practices. Additionally, these
documents are available in print to any shareholder  requesting a copy. The Code
of Ethics,  Ethical Business Conduct Statement,  Corporate Governance Guidelines
and Committee  Charters have all been approved by the Board of Directors and are
vital  to  securing  the  confidence  of  KeySpan's   shareholders,   customers,
employees, governmental authorities and the investment community.


                                       3
<PAGE>


                            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  23,000 miles of gas mains and
distribution pipelines.

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.

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.


                                       4
<PAGE>


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 and
associated   revenue  taxes)  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.  We utilize weather  derivatives for KEDNE to mitigate
variations in firm net revenues due to fluctuations in weather.

For 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.


                                       5
<PAGE>


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 2,053 MDTH (one MDTH equals 1,000 DTH or 1 billion British Thermal
Units) of gas for a peak-day  during the 2003/04  winter season and that the gas
available to us on such a peak-day  amounts to  approximately  2,076 MDTH. As of
January  20,  2004,  the  2003/04  winter  peak-day  throughput  to our New York
customers  was 1,804  MDTH,  which  occurred  on January  15, 2004 at an average
temperature of 7 degrees F, representing 87% of our peak-day capability. Our New
York firm gas peak-day capability is summarized in the following table:

<TABLE>
<CAPTION>
Source                                                 MDTH per day                    % of Total
-------------------------------------------       -------------------------       ------------------------
<S>                                                      <C>                             <C>
Pipeline                                                   794                             38%
Underground Storage                                        778                             38%
Peaking Supplies                                           504                             24%
                                                           ---                             ---
Total                                                     2,076                           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
2003/04  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  794  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,  L.P.   ("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  provided us with peak day capacity of
394 MDTH and winter  season  availability  of 2,053  MDTH.  The  peaking  supply
contracts  with the five duel fuel  power  producers  provided  us with peak day
capacity of 110 MDTH and winter season availability of 3,349 MDTH.


                                       6
<PAGE>


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 which expires on March 31, 2006.

Gas Costs. 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 firm customers.

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 January 1, 2004, approximately 105,429 gas customers
on the New York Gas Distribution System are purchasing their gas from marketers.
However, net gas revenues are not significantly  affected by customers opting to
purchase  their gas supply from other  sources since  delivery  rates charged to
transportation  customers  generally  are the same as delivery  rates charged to
sales service customers.

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, are available to
meet system requirements during the winter season.

Peak-Day Capability. The design criteria for our New England gas systems assumes
a level of 78 effective  degree days for peak-day  demand.  Under such criteria,
KEDNE  estimates that the  requirements to supply their firm gas customers would
amount to  approximately  1,281 MDTH of gas for a peak-day  during the 2003/2004
winter  season.  The gas  available to KEDNE on such  peak-day  amounts to 1,402
MDTH.  KEDNE estimates an additional 105 MDTH of on-system  throughput on behalf
of its transportation-only customers for a total peak day throughput estimate of
1,386 MDTH.

The  highest  daily  throughput,   which  includes  both  firm  sales  and  firm
transportation,  to our New England  customers was 1,421 MDTH, which occurred on
January 15, 2004 at a level of 80 effective degree days. The total throughput of
1,421  MDTH  exceeded  the design day  throughput  estimate  by two and one half
percent  (2.5%).   KEDNE  has  sufficient  gas  supply  available  to  meet  the
requirements  of their firm gas customers for the 2003/2004  winter season.  The
firm  gas  supply  peak  day  capability  of KEDNE  for its  firm  customers  is
summarized in the following table:


                                       7
<PAGE>


<TABLE>
<CAPTION>
                                                          MDTH  per
Source                                                       day                           % of Total
--------------------------------------------       -------------------------       -------------------------
<S>                                                        <C>                              <C>
Pipeline                                                    486                               35
--------------------------------------------       -------------------------       -------------------------
Underground Storage                                         261                               19
--------------------------------------------       -------------------------       -------------------------
Peaking Supplies                                            655                               47
                                                            ---                               --
--------------------------------------------       -------------------------       -------------------------
Total                                                       1402                             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 747 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 23,280 MDTH and 261 MDTH per day of maximum deliverability.

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 2003/2004 winter season, on a
peak-day,  KEDNE has access to 655 MDTH of  peaking  supplies,  47% of  peak-day
supply.

Gas  Supply  Management.   Since  April  1,  2003  the  New  England  based  gas
distribution  subsidiaries  have been  operating  under a  portfolio  management
contract with Entergy Koch Trading, LP ("EKT"). EKT provides the majority of the
city gate supply requirements to the four New England gas distribution companies
(Boston Gas,  Colonial  Gas,  Essex Gas and Energy  North) at market  prices and
manages upstream capacity, underground storage and supply contracts.

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.

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.


                                       8
<PAGE>


                           Electric Services Overview

We are the largest  electric  generator in New York State.  Our subsidiaries own
and  operate 5 large  generating  plants  and 10  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 the
Ravenswood  Generating  Station  located in Queens County,  which is the largest
generating  facility  in New  York  City.  Ravenswood  is  comprised  of 3 large
steam-generating  units and 17 gas turbine generators.  A 250MW expansion at our
Ravenswood  facility has been qualified to  participate  in the capicity  market
adminstered by the New York Independent System Operator as of April 1, 2004 (the
"Ravenswood  Expansion Project") and we operate and maintain a 55 MW gas turbine
unit in Greenport, Long Island under an agreement with Global Commons Greenport.

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 from the Long
Island units through a power supply  agreement  (the "PSA") and other  long-term
agreements to provide LIPA with approximately two thirds of its customers energy
needs;  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").
We also purchase energy,  capacity and ancillary  services in the open market on
LIPA's  behalf under 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."
Additional  electric  capacity  and energy are  supplied  under  power  purchase
agreements  with LIPA  from  four gas  turbine  units  installed  in 2002 at our
Glenwood and Port  Jefferson  sites.  See Item 7.  Management's  Discussion  and
Analysis of Financial  Condition and Results of Operation - "Electric Services -
Revenue Mechanisms" for a further discussion of these matters.

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 a portion of 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 ("Master
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 instead  conventional debt financing been employed.  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


                                       9
<PAGE>


original cost of the property, plus the present value of the lease payments that
would have otherwise been paid through June 20, 2009.  KeySpan intends to extend
the Master Lease for the  forseeable  future.  (See  discussion  concerning  the
Financial Accounting  Standards Board issued  Interpretation No. 46 in Note 7 to
the  Consolidated  Financial  Statements,  "Contractual  Obligations,  Financial
Guarantees and Contingencies."

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.  In addition,
KeySpan  intends  to  enter  into a  sale/leaseback  transaction  to  finance  a
significant  portion of the costs related to the Ravenswood  Expansion  Project.
For  further  details  on  this  proposed  transaction,   see  Note  15  to  the
Consolidated Financial Statements - "Subsequent Events."

The New York  State  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.

Forty-five of our seventy-seven  generating units are dual fuel 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 MW,  and we  instituted  a program  to reduce
nitrogen oxides for improved environmental performance.

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:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
Location of Units                 Description                   Fuel                Units             MW
---------------------------------------------------------------------------------------------------------
<S>                              <C>                           <C>                    <C>         <C>
Long Island City                  Steam Turbine                 Dual*                   3          1,765
Northport, L.I.                   Steam Turbine                 Dual*                   4          1,529
Port Jefferson, L.I.              Steam Turbine                 Dual*                   2            388
Glenwood, L.I.                    Steam Turbine                 Gas                     2            232
Island Park, L.I.                 Steam Turbine                 Dual*                   2            391
Far Rockaway, L.I.                Steam Turbine                 Dual*                   1            110
Long Island City                  GT Units                      Dual*                  17            454
Throughout L.I.                   GT Units                      Gas                     4            160
Throughout L.I.                   GT Units                      Dual*                  12            311
Throughout L.I.                   GT Units                      Oil                    30          1,093
                                                                                       --          -----

TOTAL                                                                                  77          6,433

=========================================================================================================
</TABLE>
*Dual - Oil (#2 oil, #6 residual oil) or kerosene, and natural gas.


                                       10
<PAGE>


In January  2002, we filed an  application  for approval with the New York State
Siting Board on Electric  Generation and Environment  ("Siting Board") for a 250
MW  combined  cycle  plant in  Melville,  NY. 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,  and
on May 8, 2003 the Siting Board  issued the  certificate.  In 2003,  we formed a
joint  venture with American  National  Power,  Inc.  ("ANP") for the purpose of
jointly  submitting  a proposal in repsonse to a request for  proposals by LIPA
for additional generating  resources.  The response proposed the construction of
two 250 MW plants, one at the Melville site and another at a site in the town of
Brookhaven  in Long Island  which also  received a  certificate  from the Siting
Board.  If successful in negotiating a power  purchase  agreement with LIPA, the
ANP joint venture will commence  construction  of the plant.  Otherwise,  we may
seek other  opportunities  to enter into a long-term  agreement  for the sale of
capacity,  energy and  ancillary  services.  In addition,  as part of our growth
strategy,  we  continually  evaluate the possible  acquisition or development of
additional  generating  facilities in the Northeast.  However,  we are unable to
predict  when or if such  facilities  will be  acquired or  constructed  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 (collectively,  the "LIPA
Agreements").  Under the agreements and  subsequent  Power Purchase  Agreements,
KeySpan  provides:  4,214 MW of power generation  capacity and energy conversion
services;  operation,  maintenance and capital  improvement  services for LIPA's
transmission and distribution system; and 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 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. A rate
filing reflecting the recalculated  revenue requirement was submitted to FERC on
October 31, 2003 and on December 30, 2003,  FERC issued an order  accepting,  in
part, the rates subject to refund pending  settlement  discussions and hearings.
We are unable to predict the outcome of those  proceedings  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 2003, we earned
$4 million in incentives under the PSA.


                                       11
<PAGE>


The PSA runs for a term of 15 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 7 through 10 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 2003, we earned $7.2 million in
non-cost performance incentives.


                                       12
<PAGE>


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.

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
2003, 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 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 for the terminus of a  transmission
cable under Long Island Sound and other generating facilities.


                                       13
<PAGE>


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  relates 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. In addition, costs incurred
by KeySpan for liabilities for asbestos  exposure arising from the activities of
the generating  facilities  previously  owned by LILCO are recoverable from LIPA
through the Power Supply Agreement between LIPA and KeySpan.

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

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 two lines of
business:  (i) Home Energy Services,  which provides residential  customers with
installation,  service and maintenance of energy systems and appliances, as well
as the  retail  marketing  of  electricity  to  commercial  customers;  and (ii)
Business  Solutions,  which  provides  plumbing,   heating,   ventilation,   air
conditioning  and  mechanical  services,  as well as operation and  maintenance,
design,  engineering  and  consulting  services  to  commercial  and  industrial
customers.  On May 1, 2003,  KeySpan's  gas and electric  marketing  subsidiary,
KeySpan Energy  Services,  assigned a substantial  portion of its retail natural
gas customers,  consisting mostly of residential and small commercial customers,
to ECONnergy  Energy Co.,  Inc.  ("ECONnergy").  ECONnergy is one of the largest
deregulated  energy service companies in the Northeast.  KeySpan Energy Services
is continuing its electric marketing activities.


                                       14
<PAGE>


The Energy  Services  segment has more than 2,700  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, 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.

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 who,
among  other  things,  have  reviewed  and  continue  to review and focus on our
overall strategy of these businesses.

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 pipeline
activities in the United Kingdom; and (v) certain other domestic  energy-related
investments,  such as the  transportation by truck of liquid natural gas and new
fuel cell technologies.

Gas Exploration and Production

KeySpan is engaged in the exploration for 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 the current level
of approximately  55%. This reduction in our ownership  interest is in line with
our strategy of monetizing or divesting  certain non-core assets,  which include
investment in oil and gas exploration and production  assets.  At March 1, 2004,
Houston  Exploration's  aggregate market capitalization was approximately $1.224
billion (based upon the closing price on the New York Stock Exchange on March 1,
2004  of  $38.75  per  share).  At  March  1,  2004,  Houston   Exploration  had
approximately 31,587,637 shares of common stock, $0.01 par value, outstanding.


                                       15
<PAGE>


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.

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
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 2003.  We have a total of 37 platforms
and production caissons 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,


                                       16
<PAGE>


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 412-mile  pipeline that currently  transports 1236
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. Applications for all necessary
regulatory  authorizations  were filed in 2000 and 2001. To date,  Islander East
has received a final certificate from the Federal Energy  Regulatory  Commission
("FERC")  and all  necessary  permits from the State of New York.  However,  the
State of Connecticut has denied  Islander East's  application for a coastal zone
management  permit  and a permit  under  Section  401 of the  Clean  Water  Act.
Islander  East  has  reinstated  its  appeal  of  the  State  of   Connecticut's
determination  on  the  coastal  zone  management  issue  to the  United  States
Department  of  Commerce  and is  evaluating  its legal and other  options  with
respect to the Section 401 issue.  Once in service,  the pipeline is expected to
transport  up to 260,000  DTH daily to the Long  Island and New York City energy
markets,  enough natural gas to heat 600,000 homes. The pipeline will also allow
KeySpan to diversify the geographic sources of its gas supply.  However,  we are
unable to predict when or if all regulatory approvals required to construct this
pipeline  will be  obtained.  Various  options  for the  financing  of  pipeline
construction  are  currently  being  evaluated.  At  December  31,  2003,  total
expenditures  associated  with the siting and  permitting  of the Islander  East
pipeline were $14.9 million.

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. 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 FERC. In a joint  initiative
with BG LNG  Services,  KeySpan  plans to upgrade the  KeySpan  LNG  facility to
accept  marine  deliverables  and  to  triple  vaporization  (or  regasification
capacity).  Pending regulatory approvals,  the facility could be ready to accept
marine deliverables by late 2005.


                                       17
<PAGE>


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
and, therefore, we will continue to pursue these opportunities.

Midstream Natural Gas Processing Activities in Canada

During the year,  we sold 39.09% of our  interest in KeySpan  Canada,  a company
with natural gas processing plants and gathering  facilities  located in Western
Canada.  In February  2004,  we entered into an agreement to sell an  additional
35.91%  of our  interest  in  KeySpan  Canada.  Following  the  closing  of this
additional  sale of our interest,  currently  scheduled for early April 2004, we
will own 25% of KeySpan  Canada.  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,  we sold our 20%  interest in Taylor NGL LP that owns and operates
two extraction plants also in Canada,  one located in British Columbia,  and one
in Alberta,  Canada.  We consider our Canadian  operations to be non-core assets
and we continue to evaluate 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,  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.  KeySpan considers this a non-core asset and is evaluating the possible
divestiture or monetization. In December, 2003, the company sold its interest in
Phoenix  Natural Gas  Limited,  a gas  distribution  system  serving the City of
Belfast, Northern Ireland.

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.

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  existing  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


                                       18
<PAGE>


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 in accordance with the terms of our rate recovery  agreements for each
regulated subsidiary.

Air. The Federal Clean Air Act ("CAA")  provides for the regulation of a variety
of air emissions from new and existing electric generating plants. Final permits
in accordance with the requirements of Title V of the 1990 amendments to the CAA
have  been  issued  for all of our  electric  generating  facilities,  with  the
exception of two 79 MW simple cycle gas turbine units which were  constructed in
2002.  These units currently are permitted under New York State Facility permits
and Title V permits have been timely applied for and are pending issuance by the
NYSDEC.  Renewal  applications  have been  submitted  in a timely  manner for 13
existing  facilities  whose initial permits will expire in 2004. The permits and
timely renewal  applications 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  Transport   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, II, and
III of the OTC  memorandum  in a  cost-effective  manner.  We have  achieved and
expect to continue  to achieve  such  emission  reductions  in a  cost-effective
manner through the use of low NOX combustion control systems, the use of natural
gas fuel and/or the purchases of allowances when necessary. Capital expenditures
were incurred between $10 million and $15 million for combustion control systems
and natural gas fuel  capability  additions  over the last several years enhance
compliance options.

In 2003, New York State promulgated  regulations  which will establish  separate
NOX and SO2 emission reduction requirements on electric generating facilities in
New York State  beginning  in late 2004.  KeySpan's  facilities  are expected to
comply  with  the NOX  requirements  without  material  additional  expenditures
because of previously  installed emissions control equipment.  SO2 compliance is
expected  to require a reduction  in the sulfur  content of the fuel oil used in
our  Northport  and Port  Jefferson  facilities.  Based on current  projections,
higher  incremental  fuel costs at these  facilities will be  approximately  $10
million per year, and,  contractually,  are the obligation of LIPA in accordance
with the terms of the PPA.

In December 2003, the United States  Environmental  Protection  Agency ("USEPA")
issued draft regulations that would require  reductions of mercury and nickel as
well as further reductions of NOX and SO2 from electric generating facilities on
a national  basis.  The  proposed  mercury  regulations  would have no impact on
KeySpan  facilities since their application is limited to coal-fired plants. The
proposed nickel,  NOX and SO2 reduction  requirements,  if finalized as drafted,
could require  additional  expenditures  for emission control systems or greater
use of natural gas in order to facilitate  compliance.  Until these  regulations
are finalized, the nature and extent of the financial impact on KeySpan, if any,
cannot be determined.


                                       19
<PAGE>


In 2003, the Governor of New York initiated a Regional Greenhouse Gas Initiative
that seeks to establish a coordinated  multistate plan to reduce  greenhouse gas
emissions  (primarily carbon dioxide) from electric  generating emission sources
in the Northeast. Several congressional initiatives are also under consideration
that may  also  require  greenhouse  gas  reductions  from  electric  generating
facilities  nationwide.  At the present  time, it is not possible to predict the
nature of the  requirements,  which  ultimately  will be imposed on KeySpan  nor
what,  if  any,  financial  impact  such  requirements  would  have  on  KeySpan
facilities.  However,  our  investments  in  emissions  control  technology  and
conversions to natural gas capability have resulted in a 15% reduction in carbon
dioxide emissions over the last decade,  while the electric  generation industry
as a whole  increased  carbon  dioxide  emissions  by 26%.  The  addition of the
efficient,  combined cycle unit at Ravenswood will further reduce emission rates
when it commences commercial operations in 2004.

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  nature  and cost of
equipment upgrades 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
even  before  Superfund  was  enacted  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  or its
predecessors and other potentially  responsible parties were allegedly disposed.
Normally  the  costs  associated  with  such  claims  are  allocated  among  the
potentially responsible parties on a pro rata basis. The cost of these claims is
not  presently  determinable.  Superfund  does,  however,  provide for joint and
several  liability  against  a  single  potentially  responsible  party.  In the
unlikely event that Superfund  claims were pursued against us on that basis, the
costs, 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."


                                       20
<PAGE>


Competition, Regulation and Rate Matters

Competition.  Over  the  last  several  years,  the  natural  gas  and  electric
industries  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 in 1998 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."

Ravenswood,  the merchant plant in our Electric Services segment,  is subject to
competitive and other risks that could adversely impact the market price for the
plant's output. Such risks include,  but are not limited to, the construction of
new  generation  or  transmission  capacity  serving  the New York City  market.
However,  we cannot predict when or if new generation or  transmission  capacity
will be built.

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.  Each of the  federal and state
regulators  also  regulates  certain  transactions  among our  affiliates.  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.


                                       21
<PAGE>



State Utility  Commissions.  Our regulated  utility  subsidiaries are subject to
regulation by the NYPSC,  DTE and NHPUC.  The NYPSC  regulates  KEDNY and KEDLI.
Although  KeySpan  Corporation is not regulated by the NYPSC,  it is impacted by
conditions  that  were  included  in  the  NYPSC  order   authorizing  the  1998
KeySpan/LILCO  transaction.  Those conditions  address,  among other things, 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
electricity are also subject to regulation by the NYPSC. 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.  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.  A rate  filing  reflecting  a  recalculated
revenue  requirement  was submitted to FERC on October 31, 2003. On December 30,
2003,  FERC  issued an order  accepting,  in part,  the rates  subject to refund
pending  settlement  discussions  and  hearings.  We are unable to  predict  the
outcome of those  proceedings at this time. Our Ravenswood  facility's rates are
based on a market-based  rate  application  approved by FERC. The rates that our
Ravenswood  facility may charge 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 offers 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."

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 FERC.  Our  interests  in  Iroquois,
Honeoye, Steuben and KeySpan LNG are also fully regulated by FERC as natural gas
companies.


                                       22
<PAGE>


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  and to pay  dividends  to our
shareholders.  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.

In addition,  in November 2000,  KeySpan received  authorization from the SEC to
operate three mutual  service  companies.  Under this order,  the SEC determined
that, in accordance with PUHCA, KeySpan Corporate Services LLC ("KCS"),  KeySpan
Utility Services LLC ("KUS") and KeySpan Engineering & Survey, Inc. ("KENG") may
operate to provide various services to KeySpan subsidiaries, including regulated
utility companies, at cost fairly and equitably allocated among them.

Foreign Regulation.  KeySpan's foreign operations in Northern Ireland, conducted
through Premier,  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).
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.  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

     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 NYPSC
     orders,  the  ability  of  KEDNY  and  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


                                       23
<PAGE>


     a customer service  performance  program. At the end of KEDNY's and KEDLI's
     rate years (September 30, 2003 and November 30, 2003, respectively),  their
     ratios of debt to total utility capitalization were well in compliance with
     the ratios set forth above.

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

     In addition to limiting  our  financial  activities,  PUHCA 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 April 2003,  the SEC  determined  that the  companies  that comprise our
     Energy  Services  business are  "energy-related  companies"  and  therefore
     retainable  under  existing SEC precedent.  However,  the SEC also required
     that certain of those companies  increase the percentage of their work that
     is energy related.

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.  A significant portion 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 in rates,  and the  uncertainty  of whether  regulatory
     commissions  will allow full recovery of and return on such increased costs
     and expenses.

     Various  rulemaking  proposals and market design  revisions  related to the
     wholesale  power  market are being  reviewed  at the federal  level.  These
     proposals, as well as 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, 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 FERC's  price  mitigation  measures  are  subject  to
     rehearing and possible judicial review.


                                       24
<PAGE>


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

     To mitigate our financial exposure related to commodity price fluctuations,
     KeySpan  routinely enters 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.

     In  addition,  our  business  is  subject  to many  hazards  from which our
     insurance may not  adequately  provide  coverage.  An 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 55%
     equity  interest in The Houston  Exploration  Company and our  ownership of
     KeySpan 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.

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  increases  due to
     colder  weather  conditions.  As a  result,  we  are  subject  to  seasonal
     variations in working capital because we purchase  natural gas supplies for
     storage in the second and third quarters and must 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


                                       25
<PAGE>


     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 extreme  temperature  conditions.  As a result,
     fluctuations in weather between years may have a significant  effect on our
     results of operations for these subsidiaries.  The construction  activities
     of our Energy Services subsidiaries are also affected by weather.

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  the GPRA,  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 (all Long Island units except for the 80MW facility
     at Port  Jefferson  and the 80MW  facility in  Glenwood).  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 Assurance Can Be Made that These  Arrangements Will Be Renewed at the End
of their Terms or that the  Resolution of Certain  Disputes Will Not  Materially
Impact the Financial Condition of the Company

     We derive a  substantial  portion of our revenues in our electric  services
     segment from a number 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,  the  terms  and
     conditions   thereof.   In  addition,   given  the   complexity   of  these
     arrangements, disputes arise from time to time between the Company and LIPA
     concerning  the rights and  obligations  of each party to make and  receive
     payments  as  required  pursuant  to the  terms of these  agreements.  As a
     result,  the  Company  is unable to  determine  what  effect,  if any,  the
     ultimate  resolution of these disputes will have on its financial condition
     or results of operations.

We Own Approximately 55% of Houston Exploration and Our Results of Operation are
Therefore Subject to the Risks Affecting its Business

          We  own  approximately  55% of  Houston  Exploration.  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.


                                       26
<PAGE>


          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.

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 credit rating agencies that rate our debt securities  regularly  review
     our  financial  condition  and  results of  operations.  We can  provide no
     assurances  that the ratings or outlook on our debt  securities will not be
     reduced or otherwise  negatively  changed. A negative change in the ratings
     or outlook on our debt 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 utility  subsidiaries' rate plans generally allow for
     the full recovery of the costs of investigation  and remediation of most of


                                       27
<PAGE>


     our 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  quantities  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
     write-downs of the carrying value of those businesses.

     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.

Employee Matters

As  of  December  31,  2003,  KeySpan  and  its  wholly-owned  subsidiaries  had
approximately 11,300 employees. Of that total,  approximately 5,800 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.


                                       28
<PAGE>


Prior to their expiration in February, KeySpan reached tentative agreements with
IBEW Locals 1049 and 1381 on new collective bargaining agreements.  These Unions
represent KeySpan employees in physical and clerical positions respectively, and
serve our Long Island customers. The new four-year agreements are expected to be
ratified by each respective union before the end of March 2004.

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 67, 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.
Mr. Catell also serves on the Board of Directors for Houston Exploration.

Robert J. Fani

Mr. Fani, age 50, was elected  President and Chief Operating  Officer of KeySpan
in October 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 for Strategic  Services in February
2000 and then to  President of the KeySpan  Energy  Services and Supply Group in
2001.  In January 2003,  he was named  President of KeySpan's  Energy Assets and
Supply Group until assuming his current  position in October 2003. Mr. Fani also
serves on the Board of Directors for Houston Exploration.

Wallace P. Parker Jr.

Mr. Parker,  age 54, was elected  President of the KeySpan  Energy  Delivery and
Customer  Relations  Group in January  2003. He also serves as Vice Chairman and
Chief  Executive  Officer of KeySpan  Services,  Inc. since October 2003. He had
previously  served as President,  KeySpan Energy Delivery,  since June 2001, and
from  February 2000 served as Executive  Vice  President of Gas  Operations.  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.


                                       29
<PAGE>


Steven L. Zelkowitz

Mr.  Zelkowitz,  age 54, was elected  President of KeySpan's  Energy  Assets and
Supply  Group in  October  2003.  Prior to that,  he  served as  Executive  Vice
President & Chief  Administrative  Officer since January 2003. 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. In July
2001,  Mr.  Zelkowitz  was  promoted to  Executive  Vice  President  and General
Counsel,   and  in  November  2002,  he  was  named  Executive  Vice  President,
Administration  &  Compliance,  with  responsibility  for the offices of General
Counsel,  Human Resources,  Regulatory  Affairs,  Enterprise Risk Management and
administratively  for  Internal  Auditing.   Before  joining  the  Company,  Mr.
Zelkowitz  practiced  law with  Cullen  and Dykman  LLP in  Brooklyn,  New York,
specializing  in energy and  utility law and had been a partner  since 1984.  He
served on the firm's  Executive  Committee and was head of its  Corporate/Energy
Department.

John A. Caroselli

Mr.  Caroselli,  age 49, was elected Executive Vice President and Chief Strategy
Officer in January 2003.  Mr.  Caroselli is  responsible  for Brand  Management,
Strategic Marketing, Strategic Planning, Strategic Performance, Human Resources,
and Information  Technology.  Mr.  Caroselli came to KeySpan in 2001 and at that
time served as Executive Vice President of Strategic 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.

Gerald Luterman

Mr. Luterman,  age 60, 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.  Mr. Luterman
also serves on the Board of Directors for Houston Exploration.

Anthony Nozzolillo

Mr.  Nozzolillo,  age 55, 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.


                                       30
<PAGE>


Lenore F. Puleo

Ms. Puleo,  age 50, was elected  Executive Vice President of Shared  Services in
March 2004. She previously served as Executive Vice President of Client Services
since  February  2000.  Prior to that she  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  45,  was  elected  Executive  Vice  President,  KeySpan
Corporation,  and President, KeySpan Energy Delivery New England, in April 2002.
Prior to that,  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 Company.  Before joining
Boston Gas, he was  Executive  Vice  President and Chief  Financial  Officer for
Colonial Gas Company.  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. Mr. Stavropoulos was also a director of Colonial Gas Company.

John J. Bishar, Jr.

Mr. Bishar, age 54, became Senior Vice President,  General Counsel and Secretary
on May 8, 2003, with responsibility for the Legal Services Business Unit and the
Corporate  Secretary's  Office.  Prior to that, he joined KeySpan as Senior Vice
President and General Counsel on November 1, 2002.  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 56, was elected Senior Vice President,  Regulatory Affairs and
Chief Accounting  Officer on April 1, 2003. Prior to his appointment,  he served
as Senior Vice  President of Finance  Operations  and  Regulatory  Affairs since
August 2001 and 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 Company 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.


                                       31
<PAGE>


John F. Haran

Mr. Haran,  age 53, was elected Senior Vice President of KeySpan Energy Delivery
and Chief Gas Engineer in March 2004.  He had been Senior Vice  President of gas
operations  for KEDNY and KEDLI in since 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 53, was elected Senior Vice President for Corporate Affairs 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 66, 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. He is also a member of the Board or Directors for Houston
Exploration  Company  and  KeySpan  Facilities  Income  Fund.  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.

Michael J. Taunton

Mr.  Taunton,  age 48, was named Senior Vice  President  and  Treasurer in March
2004. He had 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.




                                       32
<PAGE>

Colin P. Watson

Mr.  Watson,  age 52, 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. In support of New York City's bid to host the 2012 Olympic
games,  KeySpan has  provided  NYC2012  with the  expertise  and guidance of Mr.
Watson on a full-time basis.


Elaine Weinstein

Ms.  Weinstein,  age 57, was named  Senior Vice  President  and Chief  Diversity
Officer in March 2004.  She had served as Senior  Vice  President  of  KeySpan's
Human  Resources  division since  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.

Lawrence S. Dryer

Mr. Dryer,  44, was elected Vice President and General  Auditor in June 2003. He
previously served in this position from September 1998 to August 2001. In August
2001, he was named Senior Vice President and Chief Financial  Officer of KeySpan
Services, Inc. Prior to such positions,  Mr. Dryer had been with LILCO from 1992
to 1998 as Director of Internal Audit.  Prior to joining LILCO, Mr. Dryer was an
Audit Manager with Coopers & Lybrand.

Theresa Balog

Ms. Balog,  age 42, was named Vice  President and Controller of KeySpan in April
2003.  She joined  KeySpan  in 2002 as  Assistant  Controller.  Prior to joining
KeySpan,  Ms. Balog was Chief Accounting Officer for NiSource and held a variety
of positions with the Columbia Energy Group.



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


                                       33
<PAGE>


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.

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, 2003.


                                     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, 2004,  there
were  approximately  75,070 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:

<TABLE>
<CAPTION>
            2003                                High                    Low                     Dividends Per Share
            -------------------------------------------------------------------------------------------------------
           <S>                                 <C>                     <C>                     <C>
            First Quarter                       $38.14                  $31.02                  $0.445
            Second Quarter                      $37.51                  $31.87                  $0.445
            Third Quarter                       $35.83                  $32.30                  $0.445
            Fourth Quarter                      $37.09                  $33.64                  $0.445

            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
</TABLE>





                                       34
<PAGE>


                      EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth securities authorized for issuance under equity
compensation plans for the year ended December 31, 2003:

<TABLE>
<CAPTION>
                                                                                                       Number of securities
                                     Number of securities                                            remaining available for
                                       to be issued upon                Weighted-average              future issuance under
                                     exercise of outstanding        exercise price of equity            compensation plans
                                     options, warrants and            outstanding options,            (excluding securities
     Stock Plan category                    rights                    warrants and rights            reflected in column (a))
--------------------------------- --------------------------- ----------------------------------- ----------------------------------
                                              (a)                            (b)                               (c)
<S>                                        <C>                              <C>                           <C>
Equity compensation plans
approved by security holders
      Stock Options                         10,320,743                      $31.39                         6,783,675
      Restricted Stock                          84,318                        N/A
      Performance Shares                       186,708                        N/A
Equity compensation plans
not approved by security
holders                                            N/A                        N/A                                N/A
Total                                       10,591,769                      $31.39                         6,783,675(1)
</TABLE>

(1)  Includes  grants of  options,  restricted  stock,  and  performance  shares
     pursuant to KeySpan's  Long-Term  Incentive  Compensation Plan, as amended,
     and options  granted  pursuant to the Brooklyn  Union  Long-Term  Incentive
     Compensation  Plan and options granted pursuant to the Eastern  Enterprises
     1995  Stock  Option  Plan and the  Eastern  Enterprises  1996  Non-Employee
     Trustee's  Stock  Option  Plan,  as well as 328,000  shares of Common Stock
     issued pursuant to the Stock Plan.


















                                       35

<PAGE>


<TABLE>
<CAPTION>
Item 6. Selected Financial Data
------------------------------------------------------------------------------------------------------------------------------------
                                                                                   Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts)        2003            2002            2001             2000            1999
                                                    -------------------------------------------------------------------------------
Income Summary
<S>                                                   <C>             <C>             <C>              <C>             <C>
Revenues
     Gas Distribution                                 $ 4,161,272     $ 3,163,761     $ 3,613,551      $ 2,555,785     $ 1,753,132
     Electric Services                                  1,503,086       1,421,043       1,421,079        1,444,711         861,582
     Energy Services                                      641,432         938,761       1,100,167          770,110         186,529
     Energy Investments and other                         609,371         447,101         498,318          310,096         153,370
                                                    -------------------------------------------------------------------------------
Total revenues                                          6,915,161       5,970,666       6,633,115        5,080,702       2,954,613
                                                    -------------------------------------------------------------------------------
Operating expenses
     Purchased gas for resale                           2,495,102       1,653,273       2,171,113        1,408,680         744,432
     Fuel and purchased power                             414,633         395,860         538,532          460,841          17,252
     Operations and maintenance                         2,005,796       2,101,897       2,114,759        1,659,736       1,091,166
     Depreciation, depletion and amortization             574,074         514,613         559,138          330,922         253,440
     Early retirement and severance charges                                     -               -           65,175               -
     Operating taxes                                      418,236         381,767         448,924          421,936         366,154
                                                    -------------------------------------------------------------------------------
Total operating expenses                                5,907,841       5,047,410       5,832,466        4,347,290       2,472,444
                                                    -------------------------------------------------------------------------------
Gain on sale of property                                   15,123           4,730               -                -               -
Income from equity investments                             19,214          14,096          13,129           20,010          15,347
                                                    -------------------------------------------------------------------------------
Operating income                                        1,041,657         942,082         813,778          753,422         497,516
Other deductions                                         (340,165)       (301,253)       (359,393)        (233,410)       (102,543)
Income taxes                                              277,311         243,479         210,693          217,262         136,362
                                                    -------------------------------------------------------------------------------
Earnings from continuing operations                       424,181         397,350         243,692          302,750         258,611
                                                    -------------------------------------------------------------------------------
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)              -
Cumulative change in accounting principles                (37,451)              -               -                -               -
                                                    -------------------------------------------------------------------------------
Net income                                                386,730         377,688         224,254          300,807         258,611
Preferred stock dividend requirements                       5,844           5,753           5,904           18,113          34,752
                                                    -------------------------------------------------------------------------------
Earnings for common stock                             $   380,886     $   371,935     $   218,350      $   282,694     $   223,859
                                                    ===============================================================================
Financial Summary
Earnings per share ($)                                       2.41            2.63            1.58             2.10            1.62
Cash dividends declared per share ($)                        1.78            1.78            1.78             1.78            1.78
Book value per share, year-end ($)                          22.94           20.67           20.73            20.65           20.26
Market value per share, year-end ($)                        36.80           35.24           34.65            42.38           23.19
Shareholders, year-end                                     75,067          78,281          82,300           86,900          90,500
Capital expenditures ($)                                1,011,716       1,061,022       1,059,759          925,257         725,670
Total assets ($)                                       14,626,784      12,980,050      11,789,606       11,307,465       6,730,691
Common shareholders' equity ($)                         3,661,948       2,944,592       2,890,602        2,815,816       2,712,325
Redeemable preferred stock ($)                                  -               -               -                -         363,000
Preferred stock ($)                                        83,568          83,849          84,077           84,205          84,339
Long-term debt ($)                                      5,611,432       5,224,081       4,697,649        4,116,441       1,682,702
Total capitalization ($)                                9,356,948       8,252,522       7,672,328        7,016,462       4,479,366
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                                       36

<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;  underground gas storage;  liquefied
natural gas storage; wholesale and retail electric marketing; appliance service;
plumbing, heating,  ventilation, air conditioning and other mechanical services;
large  energy-system  ownership,   installation  and  management;   fiber  optic
services;   and  engineering  and  consulting  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 to the Consolidated Financial Statements "Business
Segments" for additional information on each operating segment.)

Consolidated Summary of Results

Operating  income by segment,  as well as  consolidated  earnings  available for
common stock is set forth in the following table for the periods indicated.
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                                                         Year Ended December 31,
 (In Thousands of Dollars, Except Per Share Amounts)              2003            2002           2001
-----------------------------------------------------------------------------------------------------------
<S>                                                            <C>             <C>           <C>
 Gas Distribution                                            $    574,254   $    531,134   $    481,393
 Electric Services                                                268,977        288,796        269,721
 Energy Services                                                  (38,066)       (11,935)      (147,485)
 Energy Investments                                               238,554        142,594        178,783
 Eliminations and other                                            (2,062)        (8,507)        31,366
                                                         -----------------------------------------------
 Operating Income                                               1,041,657        942,082        813,778
 Interest charges                                                (307,694)      (301,504)      (353,470)
 Other Income and (deductions)                                    (32,471)           251         (5,923)
 Income taxes                                                    (277,311)      (243,479)      (210,693)
                                                         -----------------------------------------------
 Income from Continuing Operations                                424,181        397,350        243,692
 Cumulative change in accounting principles                       (37,451)             -              -
 Loss from discontinued operations                                      -        (19,662)       (19,438)
                                                         -----------------------------------------------
 Net Income                                                       386,730        377,688        224,254
 Preferred stock dividend requirements                              5,844          5,753          5,904
                                                         -----------------------------------------------
 Earnings for Common Stock                                   $    380,886   $    371,935   $    218,350
                                                         ===============================================

 Basic Earnings per Share:
    Continuing operations, less preferred stock dividends    $       2.64   $       2.77   $       1.72
    Change in accounting principles                                 (0.23)             -              -
    Discontinued operations                                             -          (0.14)         (0.14)
--------------------------------------------------------------------------------------------------------
                                                             $       2.41   $       2.63   $       1.58
--------------------------------------------------------------------------------------------------------
</TABLE>




                                       37
<PAGE>



Operating income in 2003 increased $99.6 million,  or 11% compared to 2002. This
increase  in  operating   income   reflects  higher  earnings  from  the  Energy
Investments  and Gas  Distribution  segments,  somewhat  offset by  decreases in
earnings from the Electric  Services and Energy  Services  segments.  The Energy
Investment   segment   benefited  from  higher  earnings   associated  with  gas
exploration  and  production  activities  as a result  of  significantly  higher
realized gas prices and higher production volumes.  The Gas Distribution segment
benefited  from colder  weather  during the January  through  March 2003 heating
season  compared  to the same  period  last year,  as well as from load  growth.
Further,  during 2003 we recorded  $15.1 million in gains from  property  sales,
primarily 550 acres of real property located on Long Island. The Energy Services
group of  companies  were  adversely  impacted  by the  decline in  construction
industry  activity in the  Northeastern  United  States during most of the year.
Lower results from the Electric  Services  segment were  attributable  to higher
operating  costs,  as  well as  lower  revenues  from  our  merchant  generating
facility,  due in part to cooler summer weather.  (See the discussion  under the
caption "Review of Operating Segments" for further details on each segment.)

Interest  charges  increased 2% in 2003,  compared to last year,  primarily as a
result of the termination of certain  interest-rate  derivative swap instruments
that  were  in  effect  in  2002.  (See  Note  8 to the  Consolidated  Financial
Statements "Hedging, Derivative Financial Instruments and Fair Values.")

Other  income  and  (deductions)  reflects  a number of  significant  items that
impacted  comparative  results.  During  2003,  we  monetized  a portion  of our
Canadian and Northern Ireland investments, as well as a portion of our ownership
interest in The Houston  Exploration  Company ("Houston  Exploration"),  our gas
exploration  and production  subsidiary.  During the year, we sold 39.09% of our
interest in KeySpan  Canada  through an income  trust fund.  KeySpan  Canada has
natural  gas  processing  plants and  gathering  facilities  in Western  Canada.
Additionally,  we sold our 20%  interest in Taylor NGL LP that owns and operates
two  extraction  plants also  located in Canada.  We recorded a pre-tax  loss of
$30.3 million  ($34.1 million  after-tax,  or $0.22 per share)  associated  with
these sales.  Further,  in February 2004 we entered into an agreement to sell an
additional  36%  of  our  interest  in  KeySpan  Canada.  (See  Note  15 to  the
Consolidated Financial Statements "Subsequent Events.") In the fourth quarter of
2003,  we  completed  the sale of our 24.5%  interest  in Phoenix  Natural  Gas,
located in Northern Ireland, and recorded a pre-tax gain of $24.7 million, $16.0
million after-tax, or $0.10 per share.

Additionally in 2003, we reduced our ownership  interest in Houston  Exploration
from 66% to approximately 55% following the repurchase,  by Houston Exploration,
of three million shares of common stock owned by KeySpan.  We recorded a gain of
$19.0  million  on this  transaction.  Income  taxes were not  provided  on this
transaction since the transaction was structured as a return of capital.

In total, KeySpan recorded a pre-tax gain of $13.4 million from the monetization
of certain  non-core  assets.  The after-tax  gain from these three asset sales,
however,  was minimal due to the different tax  treatment  associated  with each
transaction.


                                       38
<PAGE>


Also in 2003, we called  approximately  $447 million of  outstanding  promissory
notes  that  were  issued to LIPA in  connection  with the  KeySpan/Long  Island
Lighting  Company  ("LILCO")  business  combination  completed in May 1998,  and
recorded  debt  redemption   charges  of  $18.2  million  in  other  income  and
(deductions).  Further,  Houston  Exploration  incurred costs of $5.9 million to
retire $100 million of 8.625% Notes due 2008.

Other income and (deductions) also reflects severance tax refunds totaling $21.6
million  recorded by Houston  Exploration  for severance  taxes paid in 2002 and
earlier  periods,  compared to $9.1  million  recorded in 2002,  as well as $6.5
million of realized foreign currency  translation gains.  Finally,  other income
and  (deductions)  reflects  minority  interest  adjustments  related to Houston
Exploration  and  KeySpan  Canada,  as  well  as  carrying  charges  on  certain
regulatory assets.

The increase in income tax expense in 2003 compared to 2002 generally reflects a
higher level of pre-tax  earnings.  Further income tax expense for 2003 and 2002
includes a number of items  impacting  comparative  results.  During  2003,  the
partial monetization of our Canadian investments resulted in tax expense of $3.8
million, reflecting certain United States partnership tax rules. In addition, we
recorded an adjustment to income tax expense of $6.1 million due to the state of
Massachusetts  disallowing the carry forward of net operating losses incurred by
regulated utilities. Offsetting, to some extent, these increases to tax expense,
was a tax benefit  recorded in 2003 of $9.0 million  associated with certain New
York City general corporation tax issues. In addition,  certain costs associated
with employee deferred  compensation  plans were deducted for federal income tax
purposes in 2003.  These costs,  however,  are not expensed for "book"  purposes
resulting in a beneficial permanent book-to-tax difference of $6.3 million.

Income tax expense for 2002 reflects a tax benefit of $15 million as a result of
the  favorable  resolution  of certain  outstanding  tax  issues  related to the
KeySpan/LILCO merger. Additionally, we recorded an adjustment to deferred income
taxes of $177.7  million  reflecting  a decrease  in the tax basis of the assets
acquired at the time of the merger.  This  adjustment  was a result of a revised
valuation study. Concurrent with the deferred tax adjustment, we reduced current
income taxes payable by $183.2  million,  resulting in a $5.5 million income tax
benefit.  Also,  it  should be noted  that  pre-tax  income in the  Consolidated
Statement of Income reflects minority interest adjustments, whereas income taxes
reflect the full amount of subsidiary taxes.

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

In January 2003,  the  Financial  Accounting  Standards  Board  ("FASB")  issued
Financial  Interpretation  Number  46 ("FIN  46"),  "Consolidation  of  Variable
Interest   Entities,   an  Interpretation  of  ARB  No.  51";  FIN  46  requires
consolidation of variable interest  entities.  KeySpan has an arrangement with a
variable interest entity through which we lease a portion of the  2,200-megawatt
Ravenswood  electric  generating facility  ("Ravenswood  facility").  Based upon


                                       39
<PAGE>

KeySpan's  current  status  as the  primary  beneficiary,  we were  required  to
consolidate the variable interest entity as of December 31, 2003. As a result of
implementing  FIN 46,  we  recognized  a  non-cash,  after-tax  charge  of $37.6
million,  or $0.23 per share related to "catch-up"  depreciation of the facility
since its  acquisition  in June 1999 and  recorded  the  charge as a  cumulative
change  in  accounting  principle.  (See  Note 7 to the  Consolidated  Financial
Statements "Contractual Obligations, Financial Guarantees and Contingencies" for
an explanation of the leasing arrangement for the Ravenswood  facility,  as well
as an explanation of the implementation of FIN 46.)

As a result of the above mentioned  items,  income from  continuing  operations,
less preferred stock dividends,  increased $26.7 million, or 7% in 2003 compared
to 2002. Earnings per share from continuing  operations,  however,  decreased by
$0.13 per share,  reflecting the issuance of 13.9 million shares of common stock
on January  17,  2003,  as well as the  re-issuance  of shares  held in treasury
pursuant to dividend  reinvestment  and employee  benefit plans. The increase in
average  common  shares  outstanding  reduced  2003  earnings per share by $0.32
compared  to 2002.  Comparative  earnings  available  for  common  stock,  which
includes the cumulative change in accounting principle recorded in 2003, as well
as the loss on discontinued  operations recorded in 2002, increased $9.0 million
in 2003 compared to 2002.  Earnings per share,  however,  decreased by $0.22 per
share reflecting the higher level of common stock outstanding in 2003.

KeySpan's  earnings for 2003 were forecasted to be approximately  $2.45 to $2.60
per  share,  including  the effect of the equity  issuance  in January  2003 and
excluding special items.  Earnings from continuing core operations  (defined for
this purpose as all continuing operations other than exploration and production,
less preferred stock  dividends) were  forecasted to be  approximately  $2.15 to
$2.20 per share, while earnings from exploration and production  operations were
forecasted to be  approximately  $0.30 to $0.40 per share.  Actual 2003 earnings
from  continuing  core  operations,  as  defined,  were $2.16 per  share,  while
earnings from exploration and production operations were $0.48 per share.

Operating income for the year ended December 31, 2002,  increased $128.3 million
compared to the same period in 2001. The increase in operating  income primarily
reflects the following two significant  events that are discussed in more detail
below:  (i) the  discontinuance  of goodwill  amortization in 2002; and (ii) the
recording of special items in 2001 which resulted in the  recognition of certain
gains and losses. These benefits to comparative operating income were offset, in
part, by a decrease in natural gas prices, particularly during the first quarter
of 2002, which reduced  earnings  associated with gas exploration and production
operations.  Further,  the impact of  extremely  warm  weather  during the first
quarter of 2002 adversely  impacted  natural gas consumption by gas distribution
customers and operating income in the Gas Distribution  segment. (See "Review of
Operating  Segments" for a detailed  discussion of operating  income for each of
KeySpan's lines of business.)

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.


                                       40
<PAGE>


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 $137.8
million in pre-tax  operating losses  attributed to the former Roy Kay companies
($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, as well
as  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,  pre-tax 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 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  $52.0  million  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% in 2001. 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
reflects the reversal of $11.5  million in accrued  interest  expense  resulting
from the RICO class action settlement, as noted previously.

Income tax expense  generally  reflects the level of pre-tax  income in 2002 and
2001.  However,  as noted above,  during 2002 we finalized the  valuation  study
related to the assets  transferred to KeySpan  resulting from the  KeySpan/LILCO
business  combination  completed in May 1998.  As a result of an  adjustment  to
deferred  taxes and current  income  taxes  payable,  KeySpan  recognized a $5.5
million income tax benefit. Income tax expense for 2002 also reflects additional
tax benefits of  approximately  $15 million  resulting from the  finalization of
amended tax returns and the reversal of certain tax reserves.

As a result of the above mentioned  items,  income from  continuing  operations,
less preferred  stock  dividends,  increased  $153.8 million in 2002 compared to
2001; earnings per share from continuing  operations  increased $1.05 per share.
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.


                                       41
<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.

Financial Outlook for 2004

KeySpan's  consolidated  earnings for 2004 are  forecasted to be in the range of
$2.55 to $2.75 per share, excluding special items. Earnings from continuing core
operations  (defined for this purpose as all  continuing  operations  other than
exploration and production, less preferred stock dividends) are forecasted to be
in the range of $2.20 to $2.30 per share,  while earnings from  exploration  and
production  operations  are  forecasted to be in the range of $0.35 to $0.45 per
share.

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.

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

In response to new disclosure regulations adopted by the Securities and Exchange
Commission  ("SEC") as part of its  implementation of the  Sarbanes-Oxley Act of
2002 -  specifically  Regulation G, which became  effective  March 2003 - we are
reporting  all of KeySpan's  segment  results on an  Operating  Income basis for
2003, 2002 and 2001. Management believes that this generally accepted accounting
principle  ("GAAP") based measure provides a reasonable  indication of KeySpan's
underlying  performance  associated  with its  operations.  The  following  is a
discussion  of  financial  results  achieved  by  KeySpan's  operating  segments
presented on an Operating Income basis.

Gas Distribution

KeySpan Energy Delivery New York ("KEDNY") provides gas distribution  service to
customers in the New York City Boroughs of Brooklyn, Staten Island and a portion
of  Queens.   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.



                                       42
<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)                                                   2003              2002               2001
------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>               <C>                <C>
Revenues                                                               $ 4,161,272       $ 3,163,761        $ 3,613,551
Cost of gas                                                              2,444,485         1,569,325          2,017,782
Revenue taxes                                                               90,456            83,066            119,084
------------------------------------------------------------------------------------------------------------------------
Net Gas Revenues                                                         1,626,331         1,511,370          1,476,685
------------------------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                                              659,932           608,266            593,341
   Depreciation and amortization                                           259,934           237,186            253,523
   Operating taxes                                                         147,334           135,687            148,428
------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                                 1,067,200           981,139            995,292
------------------------------------------------------------------------------------------------------------------------
Gain on the sale of property                                                15,123               903                  -
Operating Income                                                       $   574,254       $   531,134        $   481,393
------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH)                                   328,073           284,281            283,081
Transportation - Electric  Generation (MDTH)                                34,778            64,173             64,578
Other Sales (MDTH)                                                         158,722           209,002            188,037
Warmer (Colder) than Normal - New York & Long Island                         (8.0%)             7.0%              10.0%
Warmer (Colder) than Normal - New England                                   (10.0%)             4.0%               4.6%
------------------------------------------------------------------------------------------------------------------------
</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

Net gas revenues  (revenues less the cost of gas and  associated  revenue taxes)
from our gas distribution operations increased by $115.0 million, or 8%, for the
year ended December 31, 2003,  compared to last year.  Both our New York and New
England  based gas  distribution  operations  benefited  from the  significantly
colder  than normal  weather  experienced  throughout  the  Northeastern  United
States,  particularly during the primary winter heating months,  January through
March,  when our gas  distribution  operations  realize over 60% of their yearly
operating income. As measured in heating  degree-days,  weather during the first
quarter of 2003 was approximately 10% colder than normal in our New York and New
England  service  territories.  This  contrasts  with the extremely warm weather
experienced  during the first quarter of 2002 when weather was approximately 16%
- 18% warmer than normal. On a twelve month basis,  weather was approximately 8%
- 10% colder than normal in 2003 compared to 4% - 7% warmer than normal in 2002.

Net gas revenues from firm gas customers (residential, commercial and industrial
customers) in our New York service  territories  increased by $56.4 million,  or
6%, for the twelve months ended  December 31, 2003,  compared to the same period
last year. Customer additions and oil-to-gas  conversions,  net of attrition and
conservation,  added  approximately $22 million to net revenues during 2003. The
effect of higher  customer  consumption  in 2003 due  primarily  to colder  than


                                       43
<PAGE>

normal  weather,  coupled  with lower  customer  consumption  in 2002 due to the
extremely warmer than normal weather resulted in a comparative  increase to firm
net revenues of approximately  $41.1 million in 2003 compared to 2002.  However,
KEDNY and KEDLI each  operate  under a utility  tariff  that  contains a weather
normalization  adjustment  that  significantly  offsets  variations  in firm net
revenues  due to  fluctuations  from normal  weather.  These  tariff  provisions
resulted in a $20.4  million  refund to firm gas  customers  during  2003.  Also
included in net revenues are regulatory  incentives that reduced comparative net
revenues by $2.1 million and recovery of certain  taxes that added $15.8 million
to net revenues  during 2003. The recovery of taxes through  revenues,  however,
does not  impact net income  since we expense a similar  amount as  amortization
charges and income  taxes,  as  appropriate,  on the  Consolidated  Statement of
Income.

Net gas revenues from firm gas customers in our New England service  territories
increased $31.7 million,  or 7%, for the year ended December 31, 2003,  compared
to the same period last year. Customer additions and oil-to-gas conversions, net
of  attrition  and  conservation,  added  approximately  $13.5  million  to  net
revenues. As with our New York service territories,  higher customer consumption
in 2003 due to the colder  than  normal  weather,  coupled  with lower  customer
consumption  in 2002 due to the  warmer  than  normal  weather,  resulted  in an
increase in comparative net revenues for our New England based gas  distribution
utilities  of  approximately  $25.1  million in 2003  compared to 2002.  The gas
distribution  operations  of our New England  based  subsidiaries  do not have a
weather  normalization  adjustment.  To mitigate the effect of fluctuations from
normal weather patterns on KEDNE's results of operations and cash flows, weather
derivatives  were put in place for the 2002/2003 and  2003/2004  winter  heating
seasons.  Since  weather  during the first  quarter of 2003 was 10% colder  than
normal in the New England  service  territories,  we  recorded an $11.9  million
reduction  to  revenues to reflect  the loss on these  derivative  transactions.
Similarly, in 2002 we recorded a $3.3 million reduction to revenues. As a result
of these transactions,  comparative net revenues were adversely impacted by $8.6
million.  Weather  derivatives had only a marginal impact on net revenues during
the fourth quarter of 2003, since weather was approximately  normal. (See Note 8
to  the  Consolidated   Financial  Statements  "Hedging,   Derivative  Financial
Instruments and Fair Values" for further information).

Also included in net revenues for 2003 are $5.6 million of base-rate adjustments
resulting  from Boston Gas  Company's  recently  concluded  rate case.  Further,
included in net revenues for 2002,  was a benefit of $3.9 million as a result of
a favorable ruling from the Massachusetts Supreme Judicial Court relating to the
appeal by Boston Gas Company of its Performance Based Rate Plan ("PBR"). The net
effect of these base-rate  adjustments was a favorable impact to comparative net
revenues in 2003 of $1.7  million.  (See  "Regulation  and Rate  Matters"  for a
further discussion of these matters.)

Firm gas  distribution  rates for KEDNY  and KEDLI in 2003,  other  than for the
recovery of gas costs, have remained substantially  unchanged from rates charged
last year. As noted,  firm gas distribution  rates for KEDNE reflect an increase
of $5.6 million resulting from The Boston Gas Company's rate order, which became
effective November 1, 2003.


                                       44
<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  designed to compete  with prices of  alternative
fuel,  including  No. 2 and No. 6 grade  heating oil. Net revenues from sales to
these markets increased by $26.8 million during the twelve months ended December
31, 2003,  compared to the same period last year. The majority of  interruptible
profits earned by KEDNE and KEDLI are returned to firm customers as an offset to
gas costs.

During  2002,  combined net gas revenues  from our gas  distribution  operations
increased by $34.7  million,  or 2% compared to 2001.  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. Weather during
the primary heating seasons,  January through March, was  approximately  16%-18%
warmer than normal, across our service territories.

Net  revenues  from  firm  gas  customers  in our New York  service  territories
increased  $13.6  million,  or 1%, in 2002  compared  to 2001.  Included  in net
revenues are regulatory incentives and recovery of certain taxes that added $1.8
million  and  $20.1  million  to net  revenues  during  2002,  respectively.  As
mentioned previously, the recovery of taxes through revenues does not impact net
income. Excluding both the regulatory incentives and tax recoveries, comparative
net  revenues  decreased  $8.3  million.  During  2002,  our New York  based gas
distribution  utilities  added  approximately  $40  million  in  gross  gas load
additions  through  oil-to-gas  conversions,  as well as from new  construction.
Further,  as mentioned,  KEDNY and KEDLI each operate under utility tariffs that
contain a weather normalization adjustment.  These tariff provisions resulted in
an increase to net gas revenues of $22.3  million in 2002.  However the benefits
from load  additions  and the weather  normalization  adjustment  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  adversely  impacted gas
consumption in 2002.

Net  revenues  from firm gas  customers in the New England  service  territories
increased  by $20.5  million,  or 5%, in 2002  compared to 2001,  primarily as a
result of  approximately  $24 million in gross load additions.  Also included in
net revenues are base rate  adjustments  totaling $10.0 million  associated with
Boston Gas Company's 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 were 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 adversely impacted gas consumption in 2002.

As mentioned previously,  the New England-based gas distribution subsidiaries do
not have weather  normalization  adjustments.  To lessen,  to some  extent,  the
effect of  fluctuations  from  normal  weather  patterns  on KEDNE's  results of
operations and cash flows,  weather  derivatives were in place for the 2002/2003
winter  heating  season.  Since weather during the fourth quarter of 2002 was 7%


                                       45
<PAGE>

colder than normal in the New England  service  territories,  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,  remained
substantially unchanged from 2001 in all of our service territories.

Net  revenues  from sales in the  large-volume  heating and other  interruptible
(non-firm) markets were consistent between 2002 and 2001.

We are committed to our expansion  strategy initiated during the past few years.
We believe that significant growth opportunities exist on Long Island and in our
New England service  territories.  We estimate that on Long Island approximately
36% of the residential and multi-family  markets,  and  approximately 58% of the
commercial  market  currently  use natural gas for space  heating.  Further,  we
estimate that in our New England service  territories  approximately  53% of the
residential and multi-family  markets,  and  approximately 63% of the commercial
market,  currently use natural gas for space heating purposes.  We will continue
to seek growth in all our market segments, through the economic expansion of our
gas distribution  system, as well as through the conversion of residential homes
from oil-to-gas for space heating  purposes and the pursuit of  opportunities to
grow the multi-family, industrial and commercial markets.

Firm Sales, Transportation and Other Quantities

Total  actual  firm gas sales and  transportation  quantities  increased  by 15%
during the year ended December 31, 2003, compared to the same period in 2002. In
the New York service  territories  actual firm sales  increased  17%, while firm
sales in the New England service  territories  increased 13%. Weather normalized
sales quantities  increased 6% in the New York service territories and 3% in the
New  England  service  territories.  The  increases  in both  actual and weather
normalized gas sale quantities  reflect higher customer  consumption as a result
of the  significantly  colder  than  normal  weather  in  2003,  as well as from
customer  additions  and  oil-to-gas  conversions  for space  heating  purposes.
Further,  as mentioned  previously,  gas sales quantities in 2002 were adversely
impacted by the exceptionally warm weather.

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

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


                                       46
<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 have a portfolio  management contract with
Entergy Koch Trading, LP ("EKT"),  under which EKT provides all of the city gate
supply  requirements  at market prices and manages  certain  upstream  capacity,
underground storage and term supply contracts for KEDNE. These agreements expire
on March 31, 2006.

Purchased Gas for Resale

The increase in gas costs for the year ended  December 31, 2003  compared to the
same period in 2002 of $875.2  million,  or 56%,  reflects an increase of 39% in
the price per dekatherm of gas purchased,  and a 15% increase in the quantity of
gas  purchased.  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, partially offset by a 1.0% increase in the quantity of gas purchased.
The  current  gas  rate  structure  of each of our  gas  distribution  utilities
includes a purchased gas adjustment clause, pursuant to which variations between
actual  gas costs  incurred  for resale to firm  sales  customers  and gas costs
billed to firm sales  customers  are deferred and refunded to or collected  from
customers in a subsequent period.

Operating Expenses

Operating  expenses in 2003  increased  $86.1 million,  or 9%,  compared to last
year.  This  increase  is  primarily  attributable  to higher  pension and other
postretirement  benefit costs, which have increased (net of amounts deferred and
subject to regulatory  true-ups) by $30.9 million during 2003. The cost of these
benefits has risen primarily as a result of lower actual returns on plan assets,
as well as increased health care costs.  Further, the colder weather experienced
during 2003 resulted in a higher level of repair and maintenance work on our gas
distribution  infrastructure which increased  comparative  operating expenses by
approximately $15 million.

Higher depreciation and amortization expense reflects the continued expansion of
the gas distribution system. Further,  included in depreciation and amortization
expense is the amortization of certain  property taxes  previously  deferred and
currently  being  recovered in revenues.  Comparative  operating taxes reflect a
favorable $9.9 million adjustment  recorded during 2002 relating to the reversal
of excess tax reserves  established  for the  KeySpan/LILCO  combination  in May
1998.

Operating  expenses  decreased  by  $14.2  million  in 2002  compared  to  2001.
Comparative   operating   expenses   were   significantly    impacted   by   the
discontinuation of goodwill amortization. As mentioned earlier, in January 2002,
we adopted 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 $21.4 million, or 2%, in 2002 compared to 2001.


                                       47
<PAGE>


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.  Further,   depreciation  and  amortization  expense,
excluding the 2001 goodwill amortization, increased as a result of the continued
expansion of the gas distribution system.

Offsetting,  to some  extent,  these  increases  to  operating  expenses  is the
favorable $9.9 million adjustment to operating taxes recorded in 2002 related to
the reversal of certain operating tax reserves established for the KeySpan/LILCO
combination as previously noted. Further, we realized 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.

Sale of Property

During 2003 we recorded  $15.1 million in gains from property  sales,  primarily
550 acres of real property located on Long Island.

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. Cost efficient 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 to optimize the
long-term growth opportunities in our service territories.

In order to serve the  anticipated  market  requirements in our New York service
territories,  KeySpan and Duke Energy  Corporation formed Islander East Pipeline
Company,  LLC ("Islander  East") in 2000.  Islander East is owned 50% by KeySpan
and  50% by Duke  Energy,  and was  created  to  pursue  the  authorization  and
construction  of an  interstate  pipeline from  Connecticut,  across Long Island
Sound, to a terminus near Northport, Long Island. Applications for all necessary
regulatory  authorizations  were filed in 2000 and 2001. To date,  Islander East
has received a final certificate from the Federal Energy  Regulatory  Commission
("FERC")  and all  necessary  permits from the State of New York.  However,  the
State of Connecticut has denied  Islander East's  application for a coastal zone
management  permit  and a permit  under  Section  401 of the  Clean  Water  Act.
Islander  East  has  reinstated  its  appeal  of  the  State  of   Connecticut's
determination  on  the  coastal  zone  management  issue  to the  United  States
Department  of  Commerce  and is  evaluating  its legal and other  options  with
respect to the Section 401 issue.  Once in service,  the pipeline is expected to
transport  up to 260,000  DTH daily to the Long  Island and New York City energy
markets,  enough natural gas to heat 600,000 homes. The pipeline will also allow
KeySpan to diversify the geographic sources of its gas supply.  However,  we are
unable to predict when or if all regulatory approvals required to construct this
pipeline  will be  obtained.  Various  options  for the  financing  of  pipeline
construction  are  currently  being  evaluated.  At  December  31,  2003,  total
expenditures  associated  with the siting and  permitting  of the Islander  East
pipeline were $14.9 million.


                                       48
<PAGE>


Electric Services

The Electric  Services segment  primarily  consists of subsidiaries that own and
operate  oil and gas  fired  electric  generating  plants  in the New York  City
Borough of Queens (the  "Ravenswood  facility")  and the  counties of Nassau and
Suffolk on Long Island and on the  Rockaway  Peninsula  in Queens.  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)                                  2003            2002            2001
--------------------------------------------------------------------------------------------------
<S>                                                     <C>             <C>            <C>
Revenues                                               $ 1,503,187     $ 1,421,143    $ 1,421,179
Purchased fuel                                             371,134         272,873        281,398
--------------------------------------------------------------------------------------------------
Net Revenues                                             1,132,053       1,148,270      1,139,781
--------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                              650,649         659,882        662,083
   Depreciation                                             66,843          61,377         52,284
   Operating taxes                                         145,584         139,694        155,693
--------------------------------------------------------------------------------------------------
Total Operating Expenses                                   863,076         860,953        870,060
--------------------------------------------------------------------------------------------------
Gain on the sale of property                                     -           1,479              -
Operating Income                                       $   268,977     $   288,796    $   269,721
--------------------------------------------------------------------------------------------------
Electric sales (MWH)*                                    4,743,029       4,998,111      4,932,836
Capacity(MW)*                                                2,200           2,200          2,200
Cooling degree days                                          1,010           1,384          1,381
--------------------------------------------------------------------------------------------------
</TABLE>
*Reflects the operations of the Ravenswood facility only.


Net Revenues

Total electric net revenues  decreased  $16.2 million,  or 1% for the year ended
December 31, 2003 compared to the same period in 2002.

Net  revenues  from the  Ravenswood  facility  were $3.1  million  lower in 2003
compared to 2002.  Comparative net revenues reflect higher capacity  revenues of
$31.5  million,  offset by a decrease in energy  margins of $34.6  million.  The
increase  in  capacity  revenues  reflects  an increase in the level of capacity
sold,  as well as an increase in the selling price of capacity.  Such  increases
are the result of two measures.  First, in 2002, the New York Independent System
Operator ("NYISO") employed a revised methodology to assess the available supply
of and demand for  installed  capacity.  This  revised  methodology  resulted in
insufficient  capacity being procured by the market,  which caused a reliability
concern. Further, the revised methodology resulted in lower capacity volume sold
into the NYISO and depressed capacity pricing during the year ended December 31,
2002.  The  NYISO,  however,  recognized  a  calculation  flaw  in  its  revised


                                       49
<PAGE>


methodology,  and  prior  to  the  2002/2003  winter  season  capacity  auction,
corrected the  calculation  methodology  to ensure that  sufficient  capacity is
procured.  Elimination  of the flaw  ensured  compliance  with  New  York  State
reliability  rules and  resulted  in higher  capacity  revenue  realized  at the
Ravenswood facility in 2003 compared to the prior year.

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

The  decrease  in  comparative   energy  margins  in  2003  primarily   reflects
significantly cooler weather during the summer of 2003 compared to the summer of
2002. Measured in cooling degree-days, weather for 2003 was 27% cooler than last
year. The cooler weather resulted in lower realized "spark-spreads" (the selling
price of electricity  less cost of fuel, plus hedging gains or losses),  as well
as a reduction in megawatt hours sold into the NYISO.  Further, more competitive
behavior  by market  participants  that bid into the  NYISO,  as well as certain
price mitigation measures imposed by the FERC (as discussed below) have resulted
in lower comparative realized  "spark-spreads." Energy sales quantities during a
portion of 2003 were also adversely  impacted by the scheduled major overhaul of
our largest generating unit.

We  employ  derivative  financial  hedging  instruments  to hedge  the cash flow
variability  for a portion of  forecasted  purchases of natural gas and fuel oil
consumed at the  Ravenswood  facility.  Further,  we have  engaged in the use of
derivative  financial  hedging  instruments  to hedge the cash flow  variability
associated  with a portion of  forecasted  peak  electric  energy sales from the
Ravenswood  facility.  These derivative  instruments  resulted in hedging gains,
which are reflected in net electric margins, of $12.3 million for the year ended
December 31, 2003  compared to hedging gains of $17.4 million for the year ended
December  31,  2002.  (See  Note  8 to  the  Consolidated  Financial  Statements
"Hedging,  Derivative  Financial  Instruments,  and  Fair  Values"  for  further
information).


                                       50
<PAGE>


The rules and  regulations  for  capacity,  energy sales and the sale of certain
ancillary  services to the NYISO energy markets  continue to evolve and the FERC
has adopted  several  price  mitigation  measures that have  adversely  impacted
earnings from the Ravenswood facility.  Certain of these mitigation measures are
still subject to rehearing and possible judicial review. The final resolution of
these issues and their effect on our financial  position,  results of operations
and cash flows  cannot be fully  determined  at this time.  (See the  discussion
under the  caption  "Market  and Credit  Risk  Management  Activities"  for more
information.)

Net revenues from the service  agreements  with LIPA  decreased by $22.7 million
for the year ended  December  31,  2003  compared  to the same period last year.
Included in  revenues  are  billings to LIPA for certain  third party costs that
were lower than such  billings  last year.  These  revenues  have  minimal or no
impact  on  earnings  since we record a  similar  amount  of costs in  operating
expense and we share any cost under-runs with LIPA.  Excluding these third party
billings,  revenues in 2003 associated with these service  agreements  increased
approximately $7 million  compared to last year. The increase  reflects a higher
level of service fees charged to LIPA for the recovery of past operating  costs.
In 2003 we earned $16.2 million associated with non-cost performance  incentives
provided for under these agreements, compared to $16.0 million earned last year.
(For a description of the LIPA Agreements,  see the discussion under the caption
"LIPA Agreements.")

Net revenues  from the new  electric  "peaking"  facilities  located at Glenwood
Landing  and Port  Jefferson  on Long Island  were $9.6  million  higher in 2003
compared to 2002, reflecting a full year of operation. 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 added 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.

Total electric net revenues increased by $8.5 million for the year ended
December 31, 2002, compared to the same period in 2001. Net revenues in 2002
reflect net revenues of $17.3 million from the Glenwood Landing and Port
Jefferson facilities.

Net  revenues  from the LIPA  Agreements  increased  by $47.2  million  in 2002,
compared  to 2001.  Included  in  revenues  for 2002,  are  billings to LIPA for
certain third party costs that were  significantly  higher than such billings in
the prior year. As previously  mentioned,  these revenues have minimal impact on
earnings.  Excluding  these third party  billings,  revenues for 2002 associated
with the LIPA  Agreements  were  comparable to such revenues in 2001. In 2002 we
earned $16.0 million associated with non-cost  performance  incentives  provided
for under these agreements, compared to $16.2 million earned in 2001.

Net revenues from the  Ravenswood  facility were $56 million,  or 16%,  lower in
2002, compared to 2001. Net revenues from capacity sales decreased $45.3 million
compared to 2001,  while  margins  associated  with the sale of electric  energy
decreased $10.7 million.  During 2002 we changed our  classification  of certain
operating  taxes that  resulted in a  comparative  decrease  in energy  margins.
Further,  comparative  energy  sales were  adversely  impacted by a reduction in
"spark-spread."  Measured in cooling  degree-days,  weather during 2002 and 2001
was comparable.


                                       51
<PAGE>


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 NYISO
energy  market  which  lowered  capacity  clearing  prices by  approximately  8%
compared  to  2001.  Further,  as  mentioned  earlier,  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.

Derivative  instruments  resulted in hedging  gains,  which are reflected in net
electric margins, of $17.4 million for the year ended December 31, 2002 compared
to hedging  gains of $16.7  million for the year ended  December 31, 2001.  (See
Note 8 to the Consolidated  Financial Statements "Hedging,  Derivative Financial
Instruments, and Fair Values" for further information).

Operating Expenses

Operating  expenses increased $2.1 million for the year ended December 31, 2003,
compared to 2002.  Included in comparative  operating  expenses is a decrease in
third  party  capital  costs  that are fully  recoverable  from  LIPA,  as noted
previously.  Excluding the decrease in these costs, operating expenses increased
approximately $32 million.  This increase resulted, in part, from higher pension
and other  postretirement  benefit  costs.  LIPA  reimburses  KeySpan  for costs
directly  incurred by KeySpan in providing  service to LIPA,  subject to certain
sharing provisions.  Variations between pension and other  postretirement  costs
and the  estimates  used to bill LIPA are  deferred and refunded to or collected
from LIPA in subsequent  periods.  As a result of an adjustment recorded in 2002
relating to this "true-up,"  comparative pension and other  postretirement costs
were approximately $9.3 million higher in 2003 compared to 2002. In addition, in
2002 we settled certain outstanding issues with LIPA and The Consolidated Edison
Company of New York  ("Consolidated  Edison")  that  resulted in a $13.0 million
decrease to operating  expenses in 2002.  Operating taxes reflect an increase in
property tax rates  associated  with the  Ravenswood  facility.  The increase in
depreciation  expense  is  associated  with  the  Glenwood  and  Port  Jefferson
facilities.

Operating  expenses were $9.1 million lower in 2002 compared to 2001.  Excluding
the  increase in third party  capital  costs,  operating  expenses  decreased by
approximately $57 million in 2002 compared to 2001. As a result of an adjustment
recorded  in 2002  relating  to the  pension  and other  postretirement  benefit
"true-up" as previously mentioned,  comparative 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  Consolidated
Edison,  as  previously  noted,  that  resulted in a $20.3  million  decrease to
comparative operating expenses. Also in 2002 we changed our method for recording
certain  operating  taxes that resulted in a  comparative  decrease in operating
taxes. The increase in depreciation and amortization  expense primarily reflects
depreciation associated with the new peaking facilities.


                                       52
<PAGE>


Other Matters

During  2002,  construction  began  on a new 250 MW  combined  cycle  generating
facility at the Ravenswood  facility site. The new facility was  synchronized to
the electric grid in December 2003 and commenced  operational testing in January
2004. In March, the facility completed full load dependable maximum net capacity
testing.  The capacity and energy produced from this plant are anticipated to be
sold into the NYISO energy markets  during the second  quarter of 2004.  KeySpan
intends to enter into an approximately $360 million  sale/leaseback  transaction
with third  parties to finance  the cost of this  facility.  (See Note 15 to the
Consolidated  Financial Statements  "Subsequent Events" for a further discussion
regarding this proposed transaction.)

In 2003,  the New  York  State  Board  on  Electric  Generation  Siting  and the
Environment  issued  an  opinion  and  order  which  granted  a  certificate  of
environmental  capability  and public need for a 250 MW combined  cycle electric
generating  facility  in  Melville,   Long  Island,   which  is  now  final  and
non-appealable. Also in 2003, LIPA issued a Request for Proposal ("RFP") seeking
bids from  developers  to  either  build and  operate a Long  Island  generating
facility,  and/or a new cable that will link Long Island to  dedicated  off-Long
Island power of between 250 to 600 MW of electricity by no later than the summer
of 2007. KeySpan and American National Power Inc. ("ANP") filed a joint proposal
in response to LIPA's RFP. Under the proposal,  KeySpan and ANP will jointly own
and  operate  two 250 MW electric  generating  facilities  to be located on Long
Island.  It is anticipated that LIPA will respond to the joint proposal early in
2004.  At December  31, 2003,  total  expenditures  associated  with the siting,
permitting and construction of the Ravenswood expansion project, and the siting,
permitting  and  procurement  of  equipment  for the Long Island 250 MW combined
cycle electric generating facility were $387.7 million.

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

Energy Services

The Energy Services segment includes  companies that provide services to clients
located primarily within the Northeastern  United States, with concentrations in
the New York City metropolitan  area,  including New Jersey and Connecticut,  as
well as in Rhode Island,  Pennsylvania,  Massachusetts  and New  Hampshire.  The
primary lines of business are: Business Solutions and Home Energy Services.


                                       53
<PAGE>


The  table  below  highlights  selected  financial  information  for the  Energy
Services segment.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
                                                                          Year Ended December 31,
(In Thousands of Dollars)                                        2003              2002               2001
------------------------------------------------------------------------------------------------------------
<S>                                                           <C>               <C>              <C>
Revenues                                                     $ 649,590         $ 938,761        $ 1,100,167
Less: cost of gas and fuel                                      93,674           206,731            407,734
------------------------------------------------------------------------------------------------------------
Net Revenues                                                   555,916           732,030            692,433
Other operating expenses                                       593,982           743,965            839,918
------------------------------------------------------------------------------------------------------------
Operating  (Loss)                                            $ (38,066)        $ (11,935)       $  (147,485)
------------------------------------------------------------------------------------------------------------
</TABLE>

Revenues decreased 31% for the year ended December 31, 2003 compared to the same
period  last  year,  due in part to  lower  revenues  realized  by the  Business
Solutions  group of companies  as a result of the  softness in the  construction
industry in the Northeastern  United States, as well as from the discontinuation
of the general  contracting  business of one of our  subsidiaries.  The Business
Solutions  group  of  companies  provide  mechanical,   contracting,   plumbing,
engineering,   and  consulting  services  to  commercial,   institutional,   and
industrial  customers.  Further,  comparative  revenues, as well as gas and fuel
costs,  were  impacted  by the  assignment  of  retail  natural  gas  customers,
consisting  mostly of residential and small commercial  customers,  to ECONnergy
Energy Co.,  Inc.  ("ECONnergy).  KeySpan  Energy  Services  will  continue  its
electric marketing activities.

Total operating losses for the Energy Services  segment  increased $26.1 million
in 2003 compared to 2002.  Operating losses for the Business  Solutions group of
companies  increased by $32.2 million,  reflecting revenue and significant gross
margin  pressure  from the  softness  in the  construction  industry,  which has
delayed the start-up of certain engineering and construction  projects,  and has
generally  increased  competition  for  remaining  opportunities.  In  addition,
margins were impacted by certain  project-specific  losses, resulting from costs
incurred in excess of cost  recoveries,  for which some recovery may be possible
pending successful claim resolution. Business Solutions' backlog held relatively
stable at  approximately  $537  million at December  31,  2003  (which  includes
backlog of $33 million  purchased in a recent  acquisition as discussed  below),
compared to $514 million at December 31, 2002.

Offsetting,  in part, the results of the Business  Solutions group of companies,
was a  comparative  increase in operating  earnings of $6.1 million for the year
ended  December  31,  2003  associated  with the Home Energy  Services  group of
companies.  These companies provide  residential and small commercial  customers
with  service and  maintenance  contracts,  as well as the retail  marketing  of
electricity.  Comparative operating income reflects losses incurred during 2002,
resulting from the  non-renewal of appliance  service  contracts due to the warm
first quarter 2002 weather, as well as from an increase in the provision for bad
debts.

Comparative   operating   income   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.
(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
operating  loss of $137.8 million  associated  with the operations of the former


                                       54
<PAGE>


Roy  Kay  companies.   The  Roy  Kay  results   reflect  costs  related  to  the
discontinuation of the general contracting activities of these companies,  costs
to complete  work on certain loss  construction  projects,  as well as operating
losses.  During 2002, in completing the contracts entered into by the former Roy
Kay companies we incurred operating losses of $10.8 million reflecting increases
in costs to complete  construction  contracts,  and  general and  administrative
expenses. It should be noted that in 2003 we incurred $11.4 million in operating
losses which reflected  provisions made for the resolution of outstanding claims
and change orders,  as well as additional  costs incurred in connection with the
collection of outstanding contract balances.

Excluding  the  results  of the former Roy Kay  companies,  the Energy  Services
segment  reflected  an  increase  in  operating  income of $8.7  million in 2002
compared to 2001. 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
substantially  decreased its customer base by focusing its marketing  efforts on
higher net margin  customers  and in 2003  assigned  the  majority of its retail
natural gas customers to ECONnergy, as previously discussed.

Operating income for the Business Solutions group of companies improved by $22.0
million in 2002 compared to 2001. This increase reflected  additional work being
performed on the backlog of projects existing at the end of 2001 and the absence
of $6 million in losses  incurred on four major  projects in 2001.  A backlog of
approximately $514 million existed at December 31, 2002, which was 20% below the
December 31, 2001 level.

Offsetting the positive contribution to operating income in 2002 by the Business
Solutions group of companies was a decrease of $13.3 million associated with the
Home  Energy  Services  group of  companies.  Contributing  to the  decrease  in
operating income from Home Energy Services were the following  factors:  (i) the
adverse impact of the downturn in the economy in 2002;  (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 operating income in 2002 also benefited from
the  elimination  of  goodwill  amortization,  which for 2001  amounted  to $8.2
million.


Other Matters

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


                                       55
<PAGE>


Energy Investments

The Energy  Investment  segment  consists of our gas  exploration and production
operations, certain other domestic and international energy-related investments,
as well as  certain  technology-related  investments.  Our gas  exploration  and
production  subsidiaries,   Houston  Exploration  and  KeySpan  Exploration  and
Production,  LLC  ("KES  E&P")  are  engaged  in gas  and  oil  exploration  and
production,  and the development and acquisition of domestic natural gas and oil
properties.  In line  with our  strategy  of  monetizing  or  divesting  certain
non-core  assets,  in 2002 we sold a portion of our assets in the joint  venture
drilling program with Houston Exploration that was initiated in 1999. In 2003 we
reduced our ownership interest in Houston Exploration to approximately 55% (from
the previous level of 66%) through the repurchase,  by Houston  Exploration,  of
three  million  shares of common  stock  owned by KeySpan.  The net  proceeds of
approximately  $79 million received in connection with this repurchase were used
to pay  down  short-term  debt.  We  realized  a  $19.0  million  gain  on  this
transaction   that  was  recorded  in  other  income  and  (deductions)  in  the
Consolidated  Statement  of  Income.  Income  taxes  were not  provided  on this
transaction, since the transaction was structured as a return of capital.

In 2003, Houston  Exploration  acquired the entire Gulf of Mexico  shallow-water
asset base of Transworld Exploration and Production,  Inc. for $149 million. The
properties,  which are 75% natural gas, have proven reserves of approximately 92
billion cubic feet of natural gas equivalent.  Current production from 11 fields
is  approximately  35  million  cubic feet of natural  gas  equivalent  per day.
Houston  Exploration funded the transaction from its bank revolver and from cash
on hand at the time of closing.

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)                                               2003               2002              2001
-------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>                <C>               <C>
Revenues                                                            $ 501,255          $ 357,451         $ 400,031
Depletion and amortization expense                                    204,102            176,925           142,728
Full cost ceiling test write-down                                           -                  -            41,989
Other operating expenses                                               99,944             70,267            55,653
-------------------------------------------------------------------------------------------------------------------
Operating Income                                                    $ 197,209          $ 110,259         $ 159,661
-------------------------------------------------------------------------------------------------------------------
Natural gas and oil production (Mmcf)                                 109,211            106,044            93,968
Natural gas (per Mcf) realized                                         $ 4.55             $ 3.32            $ 4.24
Natural gas (per Mcf) unhedged                                         $ 5.23             $ 3.16            $ 4.09
-------------------------------------------------------------------------------------------------------------------
</TABLE>
*Operating  income above  represents  100% of our gas exploration and production
subsidiaries' results for the periods indicated. Gas reserves and production are
stated in BCFe and Mmcfe, which includes equivalent oil reserves

Operating Income

The  increase  in  operating  income of $87.0  million or 79% for the year ended
December 31, 2003,  compared to the same period of 2002,  reflects a significant
increase in revenues.  The higher  revenues were offset,  to some extent,  by an
increase in operating expenses  associated with a higher depletion rate, as well


                                       56
<PAGE>


as higher lease  operating  expenses and severance  taxes,  as discussed  below.
Revenues  for the  year  ended  2003  benefited  from the  combination  of a 37%
increase in average  realized gas prices  (average  wellhead  price received for
production  including  hedging gains and losses) and a 3% increase in production
volumes.

Derivative  financial hedging instruments are employed by Houston Exploration to
provide  more  predictable  cash  flow,  as well as to reduce  its  exposure  to
fluctuations in natural gas prices.  The average realized gas price for the year
ended 2003 was 87% of the  average  unhedged  natural  gas price,  resulting  in
revenues that were approximately $67 million lower than revenues that would have
been achieved if derivative  financial  instruments had not been in place during
2003. Houston  Exploration hedged slightly less than 70% of its 2003 production,
principally through the use of costless collars, and has hedged a similar amount
of its  estimated  2004  production.  Further,  at December  31,  2003,  Houston
Exploration has derivative financial  instruments in place for approximately 44%
of its estimated  2005  production.  (See Note 8 to the  Consolidated  Financial
Statements,  "Hedging,  Derivative Financial  Instruments,  and Fair Values" for
further information.)

The depletion rate experienced in 2003 was $1.85 per Mcf,  compared to $1.68 per
Mcf  experienced in 2002.  The increase in the depletion rate reflects  downward
reserve revisions related to performance,  the addition of more costs to Houston
Exploration's depreciation base with fewer additions for reserves, as well as an
increase in estimated future development costs at year end.

The increase in other  operating  expenses for the year ended December 31, 2003,
compared  to the  same  period  of 2002 was  primarily  due to  increased  lease
operating costs and severance taxes.  Lease operating  expenses  increased $13.1
million in 2003  compared to 2002,  as a result of the  continued  expansion  of
operations  both onshore and  offshore.  Severance  tax,  which is a function of
volume and revenues generated from onshore production, increased $6.5 million in
2003 compared to 2002 as a result of the increase in average wellhead prices for
natural  gas.  Overall  operating  expenses  are  increasing  as new  wells  and
facilities are added and production from existing wells is maintained.

Operating  income  decreased  $49.4  million  or 31% in  2002  compared  to 2001
primarily due to a 22% reduction in average  realized gas prices,  which lowered
comparative  revenues.  Further,  operating  expenses  increased  as a result of
higher  levels of  production  and a higher  depletion  rate, as well as from an
increase in lease operating  expenses.  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 approximately $16 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.


                                       57
<PAGE>


The  depletion  rate was $1.68 per Mcf for the year  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.  (See Note 1 to the Consolidated  Financial  Statements
"Summary of Significant  Accounting  Policies,"  Item F for more  information on
this charge.)

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,
                                           2003                   2002                    2001
-----------------------------------------------------------------------------------------------------
                                     BCFe         %         BCFe          %         BCFe         %
-----------------------------------------------------------------------------------------------------
<S>                                   <C>     <C>            <C>      <C>            <C>     <C>
Houston Exploration                    755      99.1%         650       96.7%         608      94.0%
KSE E&P                                  7       0.9%          22        3.3%          39       6.0%
-----------------------------------------------------------------------------------------------------
Total                                  762     100.0%         672      100.0%         647     100.0%
-----------------------------------------------------------------------------------------------------
</TABLE>

This segment also consists of KeySpan  Canada;  our 20% interest in Iroquois Gas
Transmission  System LP ("Iroquois");  our wholly owned 600,000 barrel liquefied
natural  gas ("LNG")  storage and  receiving  facility  located in Rhode  Island
("KeySpan LNG"); and our 50% interest in Premier Transmission Limited, and until
December 2003, our 24.5% interest in Phoenix  Natural Gas Limited,  both located
in Northern Ireland.

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)                                       2003          2002            2001
----------------------------------------------------------------------------------------------------
<S>                                                          <C>            <C>             <C>
Revenues                                                    $ 113,124      $ 90,778        $ 98,287
Less:  Operation and maintenance expense                       68,568        57,161          71,411
        Other operating expenses                               22,317        17,622          20,883
Add:   Equity earnings                                         19,106        13,992          13,129
        Gain on sale of property                                    -         2,348               -
----------------------------------------------------------------------------------------------------
Operating Income                                            $  41,345      $ 32,335        $ 19,122
----------------------------------------------------------------------------------------------------
</TABLE>
* Operating income above reflects 100% of KeySpan's Canada's results.


                                       58
<PAGE>


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

The  increase  in  operating  income in 2002  compared  to 2001  reflects  lower
comparative  losses  associated  with  certain  technology-related  investments.
Further, higher operating income from our Northern Ireland investments were, for
the most part,  offset by lower  earnings  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.

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

We do not  consider  certain  businesses  contained  in the  Energy  Investments
segment to be part of our core asset  group.  We have stated in the past that we
may sell or  otherwise  dispose of all or a portion of our non-core  assets.  As
previously  indicated,  in 2003 we  monetized  39.09% of our interest in KeySpan
Canada, a company with natural gas processing plants and gathering facilities in
Western  Canada.  These  assets  include 14  processing  plants  and  associated
gathering  systems that can process  approximately 1.5 BCFe of natural gas daily
and provide associated natural gas liquids  fractionation.  We sold a portion of
our interest in KeySpan Canada through the establishment of an open-ended income
fund trust (the "Fund")  organized under the laws of Alberta,  Canada.  The Fund
acquired the 39.09%  ownership  interest of KeySpan  Canada  through an indirect
subsidiary,  and then  issued 17 million  trust  units to the public  through an
initial public offering. Each trust unit represents a beneficial interest in the
Fund and is registered on the Toronto Stock Exchange (KEY.UN).  Additionally, we
sold our 20%  interest in Taylor NGL LP that owns and  operates  two  extraction
plants in Canada to AltaGas  Services,  Inc. We received cash proceeds of $119.4
million  associated with these transactions and recorded a pre-tax loss of $30.3
million ($34.1 million  after-tax).  In February 2004,  KeySpan  entered into an
agreement to sell an additional 36% of its interest in KeySpan Canada. (See Note
15 to the Consolidated Financial Statements, "Subsequent Events.")

Further,  in the fourth  quarter  of 2003,  we  completed  the sale of our 24.5%
interest  in Phoenix  Natural Gas  Limited.  We  received  cash  proceeds of $96
million and recorded a pre-tax gain of $24.7 million,  $16.0 million  after-tax,
or $0.10 per share.


                                       59
<PAGE>


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

Allocated Costs

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  non-operating  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.

The  variation in operating  income  reflected in  "eliminations  and other" for
KeySpan's non-operating subsidiaries between 2003 and 2002 primarily reflects an
adjustment   recorded  in  2003  for  environmental   reserves  associated  with
non-utility environmental sites based on a recently concluded site investigation
study.  (See  Note  7 to  the  Consolidated  Financial  Statements  "Contractual
Obligations, Financial Guarantees and Contingencies - Environmental Matters" for
additional  information on environmental  issues.) In 2001, these  non-operating
subsidiaries  realized  operating income of $31.4 million,  primarily related to
the $22.0 million benefit associated with the favorable appellate court decision
regarding the RICO class action settlement, previously mentioned.

Liquidity

Cash flow from operations for the year ended December 31, 2003 increased  $453.2
million,  or 62%,  compared to the same period last year.  During 2003,  KeySpan
performed an analysis of costs  capitalized  for  self-constructed  property and
inventory for income tax purposes.  KeySpan filed a change of accounting  method
for income tax purposes resulting in a cumulative deduction for costs previously
capitalized.  As a result of this tax  method  change,  along  with  accelerated
deductions resulting from bonus depreciation,  Keyspan received in October 2003,
a $192.3 million refund from the Internal  Revenue  Service  associated with the
refund  of prior  year  taxes,  as well as an  additional  $85  million  for tax
payments  made in 2002.  On a comparative  basis,  tax refunds  received in 2003
coupled with tax payments made in 2002, resulted in a cash flow benefit in 2003,
compared to 2002, of approximately $ 310 million.

Comparative  operating  cash flow also  reflects the  collection of gas accounts
receivable  associated with higher winter gas heating sales. As a result of load
additions,  colder than normal winter weather  during the first quarter,  higher
natural gas prices,  and higher  accounts  receivable  at the end of 2002,  cash
receipts from gas heating  customers were higher in 2003 than in 2002.  Further,
the higher  natural gas prices  resulted in an increase in  operating  cash flow
associated  with the operations of Houston  Exploration.  These benefits to cash
flow were partially offset by significantly  higher cash expenditures to re-fill
natural gas storage levels as a result of the higher natural gas prices.


                                       60
<PAGE>


Cash flow from operations  decreased by $158.7 million, or 18%, 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  pension
obligations  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 2001, as KeySpan
was  in a  refund  position  with  regard  to  such  taxes.  (See  Note 8 to the
Consolidated Financial Statements,  "Hedging,  Derivative Financial Instruments,
and Fair Values" for an explanation of the interest rate hedges.)

At December 31,  2003,  we had cash and  temporary  cash  investments  of $205.8
million.  During 2003,  we repaid  $433.8  million of  commercial  paper and, at
December 31, 2003,  $481.9  million of  commercial  paper was  outstanding  at a
weighted-average  annualized interest rate of 1.2%. We had the ability to borrow
up to an additional  $818.1 million at December 31, 2003, under the terms of our
credit facility.

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

The  credit  facility  contains  certain   affirmative  and  negative  operating
covenants,  including  restrictions  on KeySpan's  ability to mortgage,  pledge,
encumber  or  otherwise  subject its  property  to any lien,  as well as certain
financial  covenants  that  require  us  to,  among  other  things,  maintain  a
consolidated  indebtedness to consolidated  capitalization ratio of no more than
64%.  Violation of this covenant  could result in the  termination of the credit
facility and the required repayment of amounts borrowed  thereunder,  as well as
possible cross defaults under other debt agreements.


                                       61
<PAGE>


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 2002. At
December 31, 2003, consolidated  indebtedness,  as calculated under the terms of
the  credit  facility  was 58.2% of  consolidated  capitalization.  The  leasing
arrangement  associated with the Ravenswood facility ("Master Lease") has always
been treated as debt for the calculation of debt-to-total  capitalization  under
KeySpan's credit facility.  Beginning on December 31, 2003, KeySpan was required
to consolidate  the Master Lease Agreement as required by FIN 46 and as a result
the Master Lease  Agreement is  reflected  as debt on the  Consolidated  Balance
Sheet.  See  the  discussion  under  "Off-Balance  Sheet  Arrangements"  for  an
explanation of the Master Lease Agreement.

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, 2003, KeySpan was in compliance
with all covenants.

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

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

Financial  covenants  require Houston  Exploration  to, among other things,  (i)
maintain an interest  coverage ratio of at least 3.00 to 1.00 of earnings before
interest,  taxes and depreciation  ("EBITDA") to cash interest;  (ii) maintain a
total debt to EBITDA  ratio of not more than 3.50 to 1.00;  and (iii)  generally
prohibits the hedging of more than 70% of natural gas and oil production  during
any 12-month period. At December 31, 2003, Houston Exploration was in compliance
with all financial covenants.

During 2003, Houston Exploration borrowed $239 million under its credit facility
and repaid $264  million.  At December 31, 2003,  Houston  Exploration  had $127
million of borrowings  outstanding  under its credit facility at an average rate
of 3.42%. In addition,  $0.4 million was committed under outstanding  letters of
credit obligations and $172.6 million of borrowing capacity was available.


                                       62
<PAGE>


In 2003,  KeySpan Canada replaced its two outstanding credit facilities with one
new facility with three tranches that combined  allowed KeySpan Canada to borrow
up to  approximately  $125  million.  At the time of the partial sale of KeySpan
Canada,  net proceeds from the sale of $119.4  million plus an additional  $45.7
million  drawn under the new credit  facilities  were used to pay down  existing
outstanding  debt of $160.4 million.  During the third quarter of 2003,  KeySpan
Canada issued Cdn$125  million,  or  approximately  US$93 million,  in long-term
secured notes in a private placement.  The proceeds of the offering were used to
pay-down,  in its entirety,  outstanding  borrowings  under the credit facility.
Further,  one tranch of the credit  facility  was  discontinued.  (See  "Capital
Expenditures and Financing - Financing" below for further information  regarding
the long-term  debt  issuance.) At December 31, 2003,  KeySpan  Canada's  credit
facility had the following two tranches with the following maturities: (i) $37.5
million matures in 364 days: and (ii) $37.5 million matures in two years. During
2003, KeySpan Canada borrowed $71.5 million from its prior credit facilities and
repaid  $240.3  million.  During the  fourth  quarter  of 2003,  KeySpan  Canada
borrowed  $18.1 million  under the new facility and at December 31, 2003,  $56.9
million was available for future borrowing.

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

On January 17, 2003,  KeySpan  sold 13.9  million  shares of common stock on the
open market and realized net proceeds of approximately $473 million.  All shares
were offered by KeySpan pursuant to the effective shelf  registration  statement
filed with the SEC.  Net  proceeds  from the equity  sale were used to call $447
million  of  outstanding  promissory  notes to LIPA as is further  explained  in
"Capital Expenditures and Financing" below. In addition, as previously noted, we
used the net proceeds of  approximately  $79 million received in connection with
the partial monetization of Houston Exploration to repay short-term debt.

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

We  satisfy  our  seasonal  working  capital   requirements   primarily  through
internally generated funds and the issuance of commercial paper. We believe that
these  sources of funds are  sufficient  to meet our  seasonal  working  capital
needs.


                                       63
<PAGE>


Capital Expenditures and Financing

Construction Expenditures

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

-------------------------------------------------------------------------
                                               Year Ended December 31,
(In Thousands of Dollars)                      2003               2002
-------------------------------------------------------------------------
Gas Distribution                          $   419,549        $   412,433
Electric Services                             256,498            348,147
Energy Investments                            314,097            272,720
Energy Services and other                      21,572             27,722
-------------------------------------------------------------------------
                                          $ 1,011,716        $ 1,061,022
-------------------------------------------------------------------------


Construction  expenditures related to the Gas Distribution segment are primarily
for the renewal and  replacement  of mains and services and for the expansion of
the gas distribution system. Construction expenditures for the Electric Services
segment  reflect costs to: (i) maintain our generating  facilities;  (ii) expand
the  Ravenswood  facility;  and  (iii)  construct  new  Long  Island  generating
facilities as previously noted. The decrease in Electric  Services  construction
expenditures in 2003,  compared to last year reflects the fact that construction
of  the  Glenwood  and  Port  Jefferson  peaking  facilities  was  substantially
completed  by June 30,  2002.  Construction  expenditures  related to the Energy
Investments  segment primarily reflect costs associated with gas exploration and
production   activities.   These  costs  are  related  to  the  exploration  and
development  of  properties  primarily in Southern  Louisiana and in the Gulf of
Mexico.  Expenditures  also include  development costs associated with the joint
venture with Houston  Exploration,  as well as costs related to KeySpan Canada's
gas processing facilities.

Construction expenditures for 2004 are estimated to be approximately the same as
2003 at $1 billion.  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

In November 2003,  KeySpan closed on a financing  transaction  pursuant to which
$128 million  tax-exempt  bonds with a 5.25%  coupon  maturing in June 2027 were
issued  on  its  behalf.   Fifty-three   million  dollars  of  these  Industrial
Development  Revenue  Bonds were  issued  through the Nassau  County  Industrial
Development  Authority for the construction of the Glenwood  electric-generation
peaking  plant and the balance of $75  million was issued by the Suffolk  County
Industrial  Development  Authority  for the Port  Jefferson  electric-generation
peaking plant.  Proceeds from the  transaction  were used to pay down commercial
paper  used  for  the  construction,  installation  and  equipping  of  the  two
facilities.

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


                                       64
<PAGE>


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

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

In connection with the KeySpan/LILCO  business combination,  KeySpan and certain
of its  subsidiaries  issued  promissory  notes to LIPA to support  certain debt
obligations  assumed by LIPA.  At December 31,  2002,  the  remaining  principal
amount of promissory notes issued to LIPA was approximately $600 million.  Under
these  promissory  notes,  KeySpan is  required  to obtain  letters of credit to
secure its payment  obligations  if its long-term  debt is not rated at least in
the "A" range by at least two nationally recognized statistical rating agencies.
In an effort to mitigate the dilutive effect of the equity  issuance  previously
mentioned,  in March  2003,  we  called  approximately  $447  million  aggregate
principal  amount of such promissory notes at the applicable  redemption  prices
plus  accrued  and unpaid  interest  through the dates of  redemption.  Interest
savings associated with this redemption were $15.6 million  after-tax,  or $0.10
per share, in 2003.

In the fourth  quarter of 2003,  KeySpan  received  authorization  from the SEC,
under  PUHCA,  to issue up to an  additional  $3 billion of  securities  through
December 31,  2006.  This  authorization  provides  KeySpan  with the  necessary
flexibility  to finance  our  future  capital  requirements  over the next three
years.  See the  discussion  under the caption  "Regulation  and Rate  Matters -
Securities and Exchange Commission  Regulation" for a further discussion of this
approval.

We anticipate replacing outstanding commercial paper related to the construction
of a new 250 MW combined cycle  generating  facility at the Ravenswood  facility
site with the proceeds from a proposed sale/leaseback transaction anticipated to
be completed  in the second  quarter of 2004.  (See Note 15 to the  Consolidated
Financial  Statements  "Subsequent  Events" for further details on this proposed
transaction).  We will continue to evaluate our capital  structure and financing
strategy  for 2004 and beyond.  We believe  that our current  sources of funding
(i.e.,  internally  generated  funds,  the issuance of additional  securities as
noted above,  and the  availability of commercial  paper) are sufficient to meet
our anticipated capital needs for the foreseeable future.


                                       65
<PAGE>


The following table represents the ratings of our long-term debt at December 31,
2003.  Currently,  Standard & Poor's and Moody's  Investor  Services  ratings on
KeySpan's and its subsidiaries' long-term debt are on negative outlook.

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


Off-Balance Sheet Arrangements

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,  three steam generating units,  directly from Consolidated  Edison and
leased it to a KeySpan subsidiary.  The variable interest unaffiliated financing
entity  acquired  the property for $425  million,  financed  with debt of $412.3
million   (97%  of   capitalization)   and  equity  of  $12.7   million  (3%  of
capitalization).  Monthly lease payments  generally  equal the monthly  interest
expense on the debt securities.

In December  2003,  KeySpan  implemented  FIN 46 that required us to consolidate
this variable  interest  entity and classify the Master Lease as $412.3  million
long-term debt on the Consolidated Balance Sheet.  Further, we recorded an asset
on the  Consolidated  Balance  Sheet  for an amount  substantially  equal to the
estimated fair market value of the leased assets at inception of the lease, less
depreciation  since that time. As previously  mentioned,  under the terms of our
credit  facility  the  Master  Lease  has been  considered  debt in the ratio of
debt-to-total  capitalization  since the  inception of the lease and  therefore,
implementation   of  FIN  46  had  no  impact  on  our  credit   facility.   The
Interpretation also requires us to continue to depreciate the leased assets over
their  remaining  economic  lives.  (See  Note 7 to the  Consolidated  Financial
Statements,  "Contractual  Obligations,  Financial Guarantees and Contingencies"
for additional information regarding the leasing arrangement associated with the
Master Lease Agreement and FIN 46 implementation issues.)


                                       66
<PAGE>


Guarantees

KeySpan had a number of financial  guarantees for its  subsidiaries  at December
31, 2003. KeySpan has fully and unconditionally  guaranteed: (i) $525 million of
medium-term  notes issued by KEDLI;  (ii) the obligations of KeySpan  Ravenswood
LLC, the lessee under the $425 million Master Lease  Agreement  associated  with
the Ravenswood  facility;  and (iii) the payment obligations of our subsidiaries
related to $128 million of tax-exempt bonds issued through the Nassau County and
Suffolk County  Industrial  Development  Authority for the  construction  of the
Glenwood  and  Port  Jefferson   electric-generation   peaking  facilities.  The
medium-term  notes,  the Master Lease  Agreement  and the  tax-exempt  bonds are
reflected on the Consolidated  Balance Sheet.  Further,  KeySpan has guaranteed:
(i) up to $168 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 an  aggregate  amount  of $43  million;  and (iii) $67
million of subsidiary  letters of credit. The guarantee of the KEDLI medium-term
notes expires in 2010, while the Master Lease Agreement can be extended to 2009.
The  guarantee of the payment  obligations  of our  subsidiaries  related to the
tax-exempt  financing  extends to 2027. The other  guarantees have terms that do
not extend beyond 2005 and are not recorded on the  Consolidated  Balance Sheet.
At this time, we have no reason to believe that our subsidiaries will default on
their current  obligations.  However,  we cannot predict when or if any defaults
may take place or the impact such defaults may have on our consolidated  results
of  operations,   financial  condition  or  cash  flows.  (See  Note  7  to  the
Consolidated   Financial   Statements,   "Contractual   Obligations,   Financial
Guarantees and Contingencies"  for additional  information  regarding  KeySpan's
guarantees.)

In  addition,  KeySpan  intends  to  guarantee  approximately  $360  million  in
connection with a proposed sale/leaseback transaction for the financing of a new
250 MW electric generating facility located on the Ravenswood site. (See Note 15
to the Consolidated Financial Statements "Subsequent Events" for further details
regarding this transaction.)

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."


                                       67
<PAGE>


The  table  below  reflects   maturity   schedules  for  KeySpan's   contractual
obligations at December 31, 2003:
<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                           $  5,625,706       $ 1,814,999       $ 161,094        $ 3,649,613
 Capital Leases                                 12,981             3,237           2,192              7,552
 Operating Leases                              417,124           179,316         115,597            122,211
 Master Lease Payments                         169,532            92,472          61,648             15,412
 Interest Payments                           3,387,891           910,937         458,547          2,018,407
 Demand Charges                                452,045           452,045               -                  -
------------------------------------------------------------------------------------------------------------
 Total Contractual
     Cash Obligations                     $ 10,065,279       $ 3,453,006       $ 799,078        $ 5,813,195
------------------------------------------------------------------------------------------------------------
 Commercial Paper                         $    481,900       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 a method of  accounting  for  long-term
construction  type contracts in accordance  with Generally  Accepted  Accounting
Principles  and,  accordingly,  the method used for  engineering  and mechanical
contracting    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  known.  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.  Unapproved  change orders and claims also
involve the use of estimates,  and it is reasonably  possible that  revisions to
the estimated  recoverable  amounts of recorded  change orders and claims may be
made  in  the  near-term.  Application  of  percentage-of-completion  accounting
requires  that  the  impact  of  those  revised  estimates  be  reported  in the
consolidated financial statements prospectively.


                                       68
<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 Statement of Financial  Accounting  Standards ("SFAS")
142 "Goodwill and Other Intangible Assets",  significant reliance is placed upon
a  number  of  estimates   regarding  future   performance  that  require  broad
assumptions and significant  judgment by management.  A change in the fair value
of our  investments  could cause a significant  change in the carrying  value of
goodwill.  The assumptions used to measure the fair value of our investments are
the  same  as  those  used  by  us  to  prepare  yearly  operating  segment  and
consolidated  earnings and cash flow forecasts.  In addition,  these assumptions
are used to set yearly budgetary guidelines.

KeySpan currently has $1.8 billion of recorded  goodwill,  the majority of which
is  recorded  in the Gas  Distribution  and  Energy  Investments  segment,  with
approximately $171 million recorded in the Energy Services segment. As permitted
under SFAS 142, we can rely on our previous valuations for the annual impairment
testing  provided that the following  criteria for each  reporting unit are met:
(a) the assets and liabilities  that make up the reporting unit have not changed
significantly since the most recent fair value  determination;  and (b) the most
recent fair value determination resulted in an amount that exceeded the carrying
amount of the reporting  unit by a  substantial  margin and there is no economic
indication  that the carrying value of goodwill may be impaired.  In the case of
the Gas Distribution  and the Energy  Investments  segments,  the above criteria
have been met and  therefore,  there was no  impairment  to goodwill in 2003. In
regard to the Energy Services segment,  adverse economic conditions  experienced
in the construction  industry in the Northeastern  United States during 2003 and
its related impact on the operating results of this segment, prompted management
to conduct an impairment test during the fourth quarter.

KeySpan  employed a combination of two  methodologies  in  determining  the fair
value for its  investment in the Energy  Services  segment,  a market  valuation
approach and an income valuation approach.  A third party specialist was engaged
to assist with the valuation and evaluate the  reasonableness of key assumptions
employed.

Since the  companies  included in the Energy  Services  segment are not publicly
traded,  the  market  valuation  approach  was  used  to  estimate  their  total
enterprise value or aggregate potential market value. Under the market valuation
approach,  KeySpan  compared  relevant  financial  information  relating  to the
companies included in the Energy Services segment to the corresponding financial
information  for a peer group of  companies in the  specialty  trade-contracting
sector of the  construction  industry.  The market  valuation  approach  derived
enterprise value to earnings before interest and taxes ("EV/EBIT") multiples and
enterprise   value  to  earnings  before  interest,   taxes,   depreciation  and
amortization  ("EV/EBITDA") multiples.  Though there are numerous multiples that
can be used to value an individual  firm,  these  multiples  were selected since
they offer the closest  parallels to discounted cash flow valuation and are most
appropriate for the Energy Services segment's market sector.


                                       69
<PAGE>


In addition to the market valuation  approach,  we also used an income valuation
approach or discounted cash flow ("DCF") valuation approach to estimate the fair
market value for the companies  included in the Energy Services  segment.  Under
the  income  valuation  approach,  the  fair  value  of a firm  is  obtained  by
discounting  the sum of (i) the expected  future cash flows to a firm;  and (ii)
the terminal  value of a firm.  The discount  factor used in the  calculation is
basically a firm's  weighted-average  cost of capital.  KeySpan was  required to
make certain  significant  assumptions in the income approach,  specifically the
weighted-average cost of capital,  short and long-term growth rates and expected
future cash flows. The cash flow model is based on relevant  industry  forecasts
projecting  improved  market  conditions  over the next  five  years,  continued
increases in business activity that are likely to result in backlog growth,  and
short and  long-term  revenue  and  operating  margin  growth  projections  that
management believes are reasonable given historical performance.

As a result of our valuation,  management has determined  that the fair value of
the assets  adequately  exceeds their carrying value and no impairment charge is
necessary.  Management will continue to review and focus on our overall strategy
for this  business  unit and  accordingly  will continue to evaluate the related
carrying  value of the  goodwill.  While we  believe  that our  assumptions  are
reasonable, actual results, however, may differ from our projections.

Accounting for the Effects of Rate Regulation on Gas Distribution Operations

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

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

In separate  merger-related  orders issued by the DTE, the base rates charged by
Colonial  Gas Company and Essex Gas  Company  have been frozen at their  current
levels for  ten-year  periods  ending  2009 and 2008,  respectively.  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.


                                       70
<PAGE>


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 our net  regulatory  assets at December 31, 2003 could result in a
charge to net income of  approximately  $300  million or $1.89 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.

As is further  discussed  under the caption  "Regulation  and Rate  Matters," in
October 2003 the DTE rendered its decision on the Boston Gas Company's base rate
case and  Performance  Based Rate Plan  proposal  submitted  to the DTE in April
2003. The DTE approved a $27 million  increase in base  revenues,  as well as an
allowed rate of return on equity of 10.2%.  The DTE also  approved a Performance
Based Rate Plan for up to ten years.  The rate  plans  previously  in effect for
KEDNY and KEDLI have expired. The continued application of SFAS 71 to record the
activities of these  subsidiaries  is contingent  upon the actions of regulators
with regard to future rate plans.  We are currently  evaluating  various options
that may be available to us including,  but not limited to,  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 to 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. 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.  (However,  KEDNY,  although subject to SFAS 71,
does not have a recovery  mechanism  in place for  increases  in  postretirement
costs.) Further, changes in postretirement expenses associated with subsidiaries
that service the LIPA  Agreements are also deferred for future  recovery from or
refund to LIPA.


                                       71
<PAGE>


For 2003,  the assumed  long-term  rate of return on our  postretirement  plans'
assets was 8.5%  (pre-tax),  net of expenses.  This is an appropriate  long-term
expected rate of return on assets based on KeySpan's investment strategy,  asset
allocation and the historical  outperformance  of equity  investments  over long
periods  of time.  The  actual 10 year  compound  annual  rate of return for the
KeySpan Plans is greater than 8.5%.

KeySpan's master trust investment allocation policy target is 70% equity and 30%
fixed income.  At December 31, 2003,  the actual  investment  allocation was 67%
equities,  33% fixed income and cash. In an effort to maximize plan performance,
actual asset  allocation  will fluctuate from year to year depending on the then
current economic environment.

During 2003,  KeySpan  conducted  an asset & liability  study  projecting  asset
returns  and  expected  benefit  payments  over a 10-year  period.  Based on the
results,   KeySpan  has   developed  a  multiyear   funding   strategy  for  its
postretirement  plans.  KeySpan  believes that it is reasonable to assume assets
can achieve or outperform  the assumed  long-term rate of return with the target
allocation as a result of historical  outperformance of equity  investments over
long-term periods.

A 25 basis point increase or decrease in the assumed long-term rate of return on
plan assets would have impacted 2003 expense by approximately $4 million, before
deferrals.

The  year-end  December  31,  2003  assumed  discount  rate  used  to  determine
postretirement obligations was 6.25%. Our discount rate assumption is based upon
the current  investment  yield  associated  with rating agency indices that have
high quality long-term corporate bonds. A 25 basis point increase or decrease in
the assumed  year-end  discount  rate would have had no impact on 2003  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.  A year-end
discount rate of 6.00% would have  required an  additional  $11 million debit to
other comprehensive income ("OCI"), net of tax and deferrals.

At January 1, 2003, the assumed  discount rate used to determine  postretirement
obligations  was 6.75%.  A 25 basis  point  increase  or decrease in the assumed
discount  rate at the  beginning of the year would have impacted 2003 expense by
approximately $14 million, before deferrals.

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 outlook.

Historically, we have funded our qualified pension plans in excess of the amount
required to satisfy minimum ERISA funding requirements. At December 31, 2003, we
had a funding credit balance in excess of the ERISA minimum funding requirements
and as a  result  KeySpan  was not  required  to make any  contributions  to its
qualified pension plans in 2003.  However,  although we have presently  exceeded
ERISA  funding  requirements,  our pension  plans,  on an actuarial  basis,  are
currently underfunded.  Therefore,  during 2003 KeySpan contributed $137 million
to its postretirement plans.


                                       72
<PAGE>


For 2004,  KeySpan  expects to  contribute a total of $147 million to its funded
and unfunded  post-retirement  plans.  Future funding  requirements  are heavily
dependent on actual return on plan assets and prevailing interest rates.

Full Cost Accounting

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

Under full cost  accounting  rules,  total  capitalized  costs are  limited to a
ceiling equal to the present  value of future net  revenues,  discounted at 10%,
plus the lower of cost or fair  value of  unproved  properties  less  income tax
effects (the  "ceiling  limitation").  A quarterly  ceiling test is performed to
evaluate  whether  the net book value of the full cost pool  exceeds the ceiling
limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization)  less deferred  taxes are greater than the  discounted  future net
revenues or ceiling limitation, a write-down or impairment of the full cost pool
is  required.  A  write-down  of the  carrying  value of the full cost pool is a
non-cash charge that reduces  earnings and impacts  stockholders'  equity in the
period of occurrence and typically results in lower depreciation,  depletion and
amortization  expense in future  periods.  Once  incurred,  a write-down  is not
reversible at a later date.

The ceiling test is calculated  using natural gas and oil prices in effect as of
the balance sheet date,  held  constant  over the life of the reserves.  Our gas
exploration and production  subsidiaries  use derivative  financial  instruments
that qualify for hedge  accounting  under SFAS 133  "Accounting  for  Derivative
Instruments  and Hedging  Activities" 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, 2003, 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 write-down 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,


                                       73
<PAGE>


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 manage commodity and financial market risk.
All of our derivative instruments,  except for certain weather derivatives,  are
reported on the Consolidated Balance Sheet at fair value in accordance with SFAS
133;  weather  derivatives  are accounted for in accordance with Emerging Issues
Task Force ("EITF") 99-2. None of KeySpan's  derivative  instruments  qualify as
"energy trading contracts" as defined by current accounting literature.

For those derivative  instruments designated as cash flow hedges under SFAS 133,
which are the  majority  of  KeySpan's  derivative  instruments,  changes in the
market  value are  recorded in other  comprehensive  income on the  Consolidated
Balance  Sheet,  (in line  with  effectiveness  measurements)  and are  recorded
through  earnings at the time of settlement.  Hedge  effectiveness  is dependent
upon various  factors such as the use of hedge contracts with market points that
are different from the underlying transaction, and to the extent hedge contracts
are deemed ineffective, that portion will impact earnings.

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;  the accounting for
such  derivative  instruments is subject to SFAS 71. Changes in the market value
of  these  derivative   instruments  are  recorded  as  regulatory   assets  and
liabilities,  as  appropriate,  on the  Consolidated  Balance  Sheet.  KeySpan's
non-regulated subsidiaries employ a limited number of financial derivatives that
do not qualify for hedge  accounting  treatment under SFAS 133, and,  therefore,
changes in the market value of these derivative instruments are recorded through
earnings.

When available,  quoted market prices are used to record a derivative contract's
fair value.  However market values for certain  derivative  contracts may not be
readily available or determinable. If no active market exists for a commodity, a
specific  contract type, or for the entire term of a contract's  duration,  fair
values are based on pricing  models.  Such models employ matrix pricing based on
contracts with similar terms and risks, including pricing based on broker quotes
and industry  publications.  KeySpan  validates its  internally  developed  fair
values by using forecasted  market  information and  mathematical  extrapolation
techniques.  In  addition,  for  hedges  of  forecasted  transactions,   KeySpan
estimates the expected future cash flows of the forecasted transactions, as well
as evaluates  the  probability  of occurrence  and timing of such  transactions.
Changes in market conditions or the occurrence of unforeseen events could affect
the  timing  of  recognition  of  changes  in  fair  value  of  certain  hedging
derivatives.

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


                                       74
<PAGE>


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 annual 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 most recent rate
years  (September  30, 2003 and November 30, 2003,  respectively),  the ratio of
debt  to  total   utility   capitalization   was  41%  and  49%,   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
"Regulation and Rate Matters - Securities and Exchange Commission Regulation").

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 is 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  level.  The threshold level for the rate year ended
September  30, 2003 was 13.25%.  KEDNY did not earn above its  threshold  return
level in its rate year ended September 30, 2003. 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.


                                       75
<PAGE>


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, 2003. 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.

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.

Regarding  the Boston  Gas  Company,  we filed a base rate case and  Performance
Based Rate Plan on April 16,  2003,  to be  effective  in the fourth  quarter of
2003.  On October 31,  2003,  the DTE  rendered  its  decision on the Boston Gas
Company's  proposal and approved a $25.9 million  increase in base revenues with
an  allowed  return on equity of 10.2%  assuming  an equal  balance  of debt and
equity.  On  January  27,  2004 the DTE issued  orders on Boston  Gas  Company's
Motions for  Recalculation,  Reconsideration  and Clarification  that granted an
additional  $1.1 million in base revenues,  for a total of $27 million.  The DTE
also approved a true-up mechanism for pension and other  postretirement  benefit
costs under which  variations  between actual  pension and other  postretirement
benefit  costs and amounts  used to establish  rates are deferred and  collected
from or  refunded to  customers  in  subsequent  periods  through an  adjustment
clause.  This true-up  mechanism  allows for carrying charges on deferred assets
and liabilities at Boston Gas Company's weighted-average cost of capital.

The DTE also approved a  Performance  Based Rate Plan (the "Plan") for up to ten
years. The Plan allows for an annual revenue adjustment based on inflation, less
a 0.41 percent productivity factor. Further, the plan contained a margin sharing
mechanism,  whereby  25% of earnings in excess of a 15% return on equity will be
passed  back  to  customers.  Similarly,  ratepayers  would  absorb  25%  of any
shortfall below a 7% return on equity.

Prior to the  change in base  rates and the new Plan  noted  above,  Boston  Gas
Company's gas rates for local distribution  service were governed by a five-year
Performance-Based Rate Plan approved by the DTE in 1996 (the "Plan"). Under this
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 had 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%.

In connection with the Eastern  Enterprises  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


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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. 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.

Electric Rate Matters

KeySpan 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 in accordance  with the Power Supply  Agreement
("PSA") entered into between KeySpan and LIPA in 1998. The current FERC approved
rates,  which have been in effect since May 1998,  expired on December 31, 2003.
KeySpan filed with the FERC an updated cost of service for the Long Island based
oil and gas-fired  generating  plants in October 2003. The rate filing included,
among other things,  an annual revenue  increase of 2.1% or  approximately  $6.4
million,  a return on equity of 11%, updated  operating and maintenance  expense
levels and recovery of certain other costs. FERC approved  implementation of new
rates starting January 1, 2004, subject to refund.  Settlement  negotiations are
currently ongoing.

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 December  18,  2003,  provides us with,  among other
things,  authorization  to do the  following  through  December  31,  2006  (the
"Authorization  Period"):  (a) to issue and sell up to an  additional  amount of
$3.0 billion of common  stock,  preferred  stock,  preferred  and  equity-linked
securities,  and long-term debt securities (the "Long-Term  Financing Limit") in
accordance  with certain  defined  parameters;  (b) in addition to the Long-Term
Financing  Limit, to issue and sell up to an aggregate amount of $1.3 billion of
short-term  debt  (the  "Short-Term  Financing  Limit");  (c) to  issue up to 13
million  shares of common  stock under  dividend  reinvestment  and  stock-based
management  incentive and employee benefit plans;  (d) to maintain  existing and
enter  into  additional   hedging   transactions  with  respect  to  outstanding
indebtedness in order to manage and minimize  interest rate costs;  (e) to issue
guarantees  and other forms of credit support in an aggregate  principal  amount


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not  to  exceed  $4.0  billion  outstanding  at any  one  time;  (f) to  refund,
repurchase   (through   open  market   purchases,   tender   offers  or  private
transactions), replace or refinance debt or equity securities outstanding during
the  Authorization  Period  through the issuance of similar or any other type of
authorized securities;  (g) to pay dividends out of capital and unearned surplus
as well as  paid-in-capital  with  respect to certain  subsidiaries,  subject to
certain  limitations;  (h) to engage in preliminary  development  activities and
administrative   and  management   activities  in  connection  with  anticipated
investments in exempt wholesale generators,  foreign utility companies and other
energy-related  companies;  (i) to organize and/or acquire the equity securities
of entities that will serve the purpose of facilitating  authorized  financings;
(j) to invest up to $3.0  billion in exempt  wholesale  generators  and  foreign
utility  companies;  (k) to create  and/or  acquire the  securities  of entities
organized  for the  purpose of  facilitating  investments  in other  non-utility
subsidiaries;  and (l) to enter into  certain  types of  affiliate  transactions
between certain  non-utility  subsidiaries  involving cost structures  above the
typical "at-cost" limit.

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.  As of December 31, 2003 our consolidated  common equity was 38%
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")

KeySpan manages the day-to-day operations,  maintenance and capital improvements
of the transmission and distribution ("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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Power Supply Agreement ("PSA")

KeySpan 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. As noted previously,  rates under the PSA have
been  reestablished  for the contract  year  commencing  January 1, 2004.  Rates
charged to LIPA include a fixed and variable  component.  The variable component
is billed to LIPA on a monthly per  megawatt  hour 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.  The
PSA runs for a term of fifteen  years  through  May 2013,  with LIPA  having the
option to renew the PSA for an additional fifteen year term.

Energy Management Agreement ("EMA")

The EMA  provides  for KeySpan 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 is expected to be in effect through 2013 for
the  procurement  of fuel  supplies and through 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 originally 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.


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The extension is the result of an 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  (the "PPAs") with LIPA.
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.  During  2003,  we undertook an extensive
review of all our  current and former  properties  that are or may be subject to
environmental cleanup activities. As a result of this study, we adjusted reserve
balances for  estimated  manufactured  gas plant ("MGP")  related  environmental
cleanup activities,  as well as estimated environmental cleanup costs related to
three  non-utility  sites.  Through various rate orders issued by the NYPSC, DTE
and NHPUC,  costs related to MGP environmental  cleanup activities are recovered
in rates charged to gas distribution customers and, as a result,  adjustments to
these reserve balances do not impact earnings.  However,  environmental  cleanup
activities  related  to the  three  non-utility  sites are not  subject  to rate
recovery.  Based on the recently  concluded  environmental  study we reduced our
reserve  balance for future  cleanup costs related to these sites and realized a
pre-tax operating income benefit of $10 million.


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We estimate that the  remaining  cost of our MGP related  environmental  cleanup
activities,  including costs  associated with the Ravenswood  facility,  will be
approximately  $269.1 million and we have recorded a related  liability for such
amount.   We  have  also  recorded  an  additional   $25.6  million   liability,
representing the estimated  environmental cleanup costs related to a former coal
tar  processing  facility.  As of December 31, 2003, we have expended a total of
$101.1 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.)


Market and Credit Risk Management Activities

Market Risk: KeySpan is 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.

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

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

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


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Equity  and Debt  Securities  Risk:  KeySpan  is  exposed  to price  risk due to
investments  in equity and debt  securities  held to fund  benefit  payments for
various employee pension and other  postretirement  benefit plans. To the extent
that the values of  investments  held  decline,  the effect will be reflected in
KeySpan's  recognition  of periodic cost of such employee  benefit plans and the
determination  of the amount of cash to be contributed  to the employee  benefit
plans.

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 January
27, 2004,  the NYPSC  issued a notice  seeking  further  comments on the matters
addressed in the RD, in light of the current  state of the retail market and the
experience of the past few years.

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.  The Joint Proposal expired on
November 30, 2003.  However, by Order dated November 25, 2003 the NYPSC approved
tariff  amendments that allow KEDNY and KEDLI to continue the merchant  function
backout credit and the lost revenue recovery mechanism through May 31, 2005.


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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
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.  Pursuant to
the Act, the NYPSC proposed regulations implementing the Act through a notice of
Proposed Rulemaking dated January 27, 2004. The Act became 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 LDCs'  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. In January 2004, the DTE began a proceeding
to  re-examine  whether  the  upstream  capacity  market  has been  sufficiently
competitive to allow voluntary capacity assignment.

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.


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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.

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.  On  September  16,  2004,  FERC
terminated  various  RTO  proceedings,  including  the  NYISO/ISONE  proceeding,
because it determined  their  continuation is no longer necessary to achieve the
Commission's  objective  of  establishing  RTOs.  Nevertheless,  the  Commission
continues to guide the  evolution of  competitive  markets in other  proceedings
including the development of a Standard Market Design.

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.


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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 implemented a new in-City real time
automated mitigation procedure.  On November 26, 2003, the NYISO filed with FERC
a request  for  tariff  revisions  reflecting  the  implementation  of  enhanced
real-time  scheduling  software.  Among other things,  the new software included
changes  to the  in-City  day-ahead  energy  mitigation  measures.  The  in-City
day-ahead  energy  mitigation  will no longer use the Indian  Point 2 price as a
proxy for determining whether an energy offer should be mitigated.  The NYISO is
going to apply its conduct and impact mitigation scheme to in-City offers.  This
will be applied on an hour by hour basis rather than on a 24-hour basis. Overall
the changes are intended to address  longstanding issues in the NYISO market and
help the NYISO markets reach their full potential. The revisions are expected to
lead to prices  that  reflect  actual  market and system  conditions,  including
scarcity conditions. FERC approved the tariff revisions on February 11, 2004 and
the NYISO  will  implement  the  revisions  when they  complete  testing  of the
software  revisions in the fall of 2004.  However,  the NYISO will implement the
revisions  associated  with the  in-City  mitigation  measures  in its  existing
systems before the summer of 2004.  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.

NYISO Demand Curve Capacity Market Implementation

On March 21, 2003 the NYISO made a filing at FERC  seeking  approval of a Demand
Curve  to be used in  place  of its  current  deficiency  auction  for  capacity
procurement. On May 20, 2003, FERC approved, with some modifications, the Demand
Curve to become effective May 21, 2003. On October 23, 2003, FERC denied various
requests for rehearing of its order  approving the Demand Curve and approved the
NYISO's compliance filing. On December 9, 2003, the NYISO filed its first status
report with FERC with  respect to how the Demand  Curve was  working.  The NYISO
report found that there was no evidence of inappropriate withholding of capacity
resources  and that the Demand  Curve was working as  intended.  On December 22,
2003,  the  Electric  Consumers  Resource  Council  filed an appeal  with the DC
Circuit Court of Appeals of FERC's May 20, 2003 order approving the Demand Curve
and its October 23, 2003 order denying rehearing. This case is still pending and
we are unable to determine to what extent,  if any, this  proceeding will impact
the Ravenswood  facility's  financial  condition,  results of operations or cash
flows.

10-Minute Non-Spinning Reserves - DC Court of Appeals

Due to  volatility  in the  market  clearing  price of  10-minute  spinning  and
non-spinning reserves during the first quarter of 2000, the NYISO requested that
FERC approve a bid cap on reserves as well as requiring a refunding of so called
alleged "excess payments" received by sellers,  including Ravenswood. On May 31,
2000, FERC issued an order that granted  approval of a $2.52 per MWh bid cap for
10 minute non-spinning  reserves,  plus payments for the opportunity cost of not


                                       85
<PAGE>


making  energy  sales.  The  other  requests,  such as a bid  cap  for  spinning
reserves,  retroactive refunds,  recalculation of reserve prices for March 2000,
and convening a technical conference and settlement proceeding, were rejected.

The NYISO,  Con Edison,  Niagara Mohawk Power  Corporation and Rochester Gas and
Electric (joint petitioners) each individually  appealed FERC's order to Federal
court. The appeals were  consolidated into one case by the court. On November 7,
2003 the United  States  Court of Appeals  for the  District  of  Columbia  (the
"Court") issued its decision in the case of  Consolidated  Edison Company of New
York, Inc., v. Federal Energy Regulatory Commission  ("Decision").  Essentially,
the Court found errors in the Commission's  decision and remanded some issues in
the  case  back to the  Commission  for  further  explanation  and  action.  The
Commission  has not acted on the  remand.  At this time we can not  predict  the
outcome of the remand proceeding.

Foreign Currency Fluctuations

We  follow  the  principles  of SFAS  52,  "Foreign  Currency  Translation"  for
recording our investments in foreign  affiliates.  At December 31, 2003, the net
assets of these  affiliates was  approximately  $323 million and at December 31,
2003, the accumulated  after-tax foreign currency  translation included in Other
Comprehensive  Income  was a  credit  of  $26.5  million.  (See  Note  1 to  the
Consolidated Financial Statements "Summary of Significant Accounting Policies.")

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

Financially-Settled  Commodity  Derivative  Instruments - Non-Regulated  Hedging
Activities:  From time to time,  KeySpan  subsidiaries have utilized  derivative
financial  instruments,  such as futures,  options and swaps, for the purpose of
hedging the cash flow variability  associated with changes in commodity  prices.
KeySpan is exposed to  commodity  price risk  primarily  with  regard to its gas
exploration and production  activities and its electric  generating  facilities.
Derivative  financial  instruments are employed by Houston  Exploration to hedge
cash flow  variability  associated  with  forecasted  sales of natural  gas. The
Ravenswood facility uses derivative financial instruments to hedge the cash flow
variability  associated  with the  purchase  of natural gas and oil that will be
consumed  during the generation of  electricity.  The  Ravenswood  facility also
hedges the cash flow  variability  associated  with a portion  of peak  electric
energy sales.

For  derivative  instruments  associated  with gas  exploration  and  production
activities,  KeySpan uses standard New York Mercantile Exchange ("NYMEX") future
price  quotes  to  value  swap   positions  and  published   volatility  in  its
Black-Scholes   calculation  for  outstanding  options.  Further,  KeySpan  uses
standard NYMEX futures  prices to value gas futures  contracts and market quoted
forward prices to value oil swap and natural gas basis swap contracts associated
with its Ravenswood facility.  We also use market quoted forward prices to value
electric derivatives associated with the Ravenswood facility.


                                       86
<PAGE>


The following tables set forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2003.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                                     Year of      Volumes       Floor     Ceiling        Fixed Price     Current Price   Fair Value
          Type of Contract           Maturity      (mmcf)        ($)        ($)              ($)             ($)           ($000)
-----------------------------------------------------------------------------------------------------------------------------------
               Gas
<S>                                    <C>      <C>          <C>         <C>               <C>          <C>               <C>
Collars                                 2004      64,100      3.75-4.13   5.05-6.02            -         5.11 - 6.19       (29,449)
                                        2005      36,500           4.50        5.50            -         4.65 - 5.61        (1,534)

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

Swaps/Futures - Short Natural Gas       2004      14,640              -           -         4.96         5.11 - 6.19        (6,912)
                                        2005      18,250              -           -         4.77         4.65 - 5.61        (3,194)

Swaps/Futures - Long Natural Gas        2005          10              -           -         4.95                4.65            (6)

-----------------------------------------------------------------------------------------------------------------------------------
                                                 142,600                                                                   (36,867)
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
                                        Year of         Volumes        Fixed Price         Current Price        Fair Value
          Type of Contract              Maturity       (Barrels)            ($)                  ($)              ($000)
--------------------------------------------------------------------------------------------------------------------------
              Oil
<S>                                       <C>          <C>            <C>                  <C>                      <C>
Swaps - Long Fuel Oil                      2004         100,548        20.55 - 29.60        28.28 - 32.42            361
                                           2005          28,000        24.65 - 27.25                27.35             24
--------------------------------------------------------------------------------------------------------------------------
                                                        128,548                                                      385
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                                      Year of                         Fixed Price         Current Price           Fair Value
       Type of Contract               Maturity           MWh              ($)                   ($)                 ($000)
------------------------------------------------------------------------------------------------------------------------------
         Electricity
<S>                                   <C>               <C>         <C>                   <C>                       <C>
Swaps - Energy                         2004              580,000     14.00 - 28.00         14.10 - 39.33             259

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


The  following  tables  detail the  changes in and sources of fair value for the
above derivatives:

------------------------------------------------------------------------------
(In Thousands of Dollars)                                               2003
Change in Fair Value of Derivative Hedging Instruments                 ($000)
------------------------------------------------------------------------------
Fair value of contracts at January 1,                               $ (32,628)
Net losses on contracts realized                                       35,449
(Decrease) in fair value of all open contracts                        (39,045)
------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31,                 $ (36,224)
------------------------------------------------------------------------------


                                       87
<PAGE>


<TABLE>
<CAPTION>

---------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
---------------------------------------------------------------------------------------------------------
                                                                  Fair Value of Contracts
---------------------------------------------------------------------------------------------------------
                                                     Maturity               Maturity              Total
Sources of Fair Value                              In 12 Months              in 2005           Fair Value
---------------------------------------------------------------------------------------------------------
<S>                                                 <C>                      <C>               <C>
Prices actively quoted                              $ (23,142)              $ (3,677)          $ (26,819)
Prices provided by external sources                        (3)                     -                  (3)
Prices based on models and
    other valuation methods                            (8,992)                (1,054)            (10,046)
Local published indicies                                  620                     24                 644
---------------------------------------------------------------------------------------------------------
                                                    $ (31,517)              $ (4,707)          $ (36,224)
---------------------------------------------------------------------------------------------------------
</TABLE>


Firm Gas Sales Derivative  Instruments - Regulated Utilities:  We use derivative
financial  instruments to reduce the cash flow  variability  associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations.  The accounting for these derivative instruments is
subject to SFAS 71 "Accounting  for the Effects of Certain Types of Regulation."
Therefore,  changes in the fair value of these derivatives have been recorded as
a regulatory asset or regulatory  liability on the  Consolidated  Balance Sheet.
Gains or losses on the settlement of these contracts are initially  deferred and
then refunded to or collected from our firm gas sales customers  consistent with
regulatory requirements.

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

-----------------------------------------------------------------------------------------------------------------------------------
                           Year of       Volumes       Floor          Ceiling       Fixed Price        Current Price     Fair Value
   Type of Contract        Maturity       (mmcf)         ($)             ($)            ($)                ($)             ($000)
-----------------------------------------------------------------------------------------------------------------------------------
<S>                        <C>           <C>        <C>             <C>              <C>              <C>                 <C>
Options                     2004           6,460     3.75 - 5.00     4.75 - 6.00                -      5.11 - 6.19         3,008

Swaps                       2004          17,122               -               -      4.42 - 6.23      5.11 - 6.19         6,501
                            2005           3,310               -               -      4.61 - 5.65      4.65 - 5.61           352
-----------------------------------------------------------------------------------------------------------------------------------
                                          26,892                                                                           9,861
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

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









                                       88
<PAGE>

Item 8. Financial Statements and Supplementary Data
<TABLE>

                           CONSOLIDATED BALANCE SHEET
<CAPTION>
--------------------------------------------------------------------------------------------------------
                                                                              Year Ended December 31,
(In Thousands of Dollars)                                                   2003                  2002
--------------------------------------------------------------------------------------------------------

ASSETS
<S>                                                                    <C>                  <C>
Current Assets
     Cash and temporary cash investments                            $      205,751       $      170,617
     Accounts receivable                                                 1,029,459            1,122,022
     Unbilled revenue                                                      505,633              473,060
     Allowance for uncollectible accounts                                  (79,184)             (63,029)
     Gas in storage, at average cost                                       488,521              297,060
     Material and supplies, at average cost                                121,415              113,519
     Other                                                                 115,304               93,980
                                                             -------------------------------------------
                                                                         2,386,899            2,207,229
                                                             -------------------------------------------

Investments and  Other                                                     248,565              264,729
                                                             -------------------------------------------

Property
     Gas                                                                 6,522,251            6,125,529
     Electric                                                            2,636,537            1,974,352
     Other                                                                 425,576              394,374
     Accumulated depreciation                                           (2,610,876)          (2,374,772)
     Gas exploration and production, at cost                             3,088,242            2,438,998
     Accumulated depletion                                              (1,167,427)            (973,889)
                                                             -------------------------------------------
                                                                         8,894,303            7,584,592
                                                             -------------------------------------------

Deferred Charges
     Regulatory assets                                                     564,985              438,516
     Goodwill and other intangible assets, net
      of amortization                                                    1,809,712            1,796,225
     Other                                                                 722,320              688,759
                                                             -------------------------------------------
                                                                         3,097,017            2,923,500
                                                             -------------------------------------------

Total Assets                                                        $   14,626,784       $   12,980,050
                                                             ===========================================
</TABLE>
        See accompanying Notes to the Consolidated Financial Statements.


                                       89

<PAGE>

<TABLE>

                           CONSOLIDATED BALANCE SHEET
<CAPTION>
----------------------------------------------------------------------------------------------------------
                                                                               Year Ended December 31,
(In Thousands of Dollars)                                                    2003                  2002
----------------------------------------------------------------------------------------------------------

LIABILITIES AND CAPITALIZATION
<S>                                                                    <C>                    <C>
Current Liabilities
     Current redemption of long-term debt                          $         1,471        $        11,413
     Accounts payable and other liabilities                              1,141,597              1,096,654
     Commercial paper                                                      481,900                915,697
     Dividends payable                                                      72,289                 64,714
     Taxes accrued                                                          46,580                 51,276
     Customer deposits                                                      40,370                 38,387
     Interest accrued                                                       64,609                 77,092
                                                            ----------------------------------------------
                                                                         1,848,816              2,255,233
                                                            ----------------------------------------------

Deferred Credits and Other Liabilities
     Regulatory liabilities:
       Miscellaneous liabilities                                           104,034                 84,479
       Removal costs recovered                                             450,034                      -
     Removal costs recovered                                                     -                365,744
     Deferred income tax                                                 1,273,651                877,013
     Postretirement benefits and other reserves                            961,962                759,731
     Other                                                                 121,790                154,907
                                                            ----------------------------------------------
                                                                         2,911,471              2,241,874
                                                            ----------------------------------------------

Commitments and Contingencies (See Note 7)                                       -                      -

Capitalization
     Common stock                                                        3,487,645              3,005,354
     Retained earnings                                                     621,430                522,835
     Accumulated other comprehensive income                                (68,640)              (108,423)
     Treasury stock                                                       (378,487)              (475,174)
                                                            ----------------------------------------------
          Total common shareholders' equity                              3,661,948              2,944,592
     Preferred stock                                                        83,568                 83,849
     Long-term debt                                                      5,611,432              5,224,081
                                                            ----------------------------------------------
Total Capitalization                                                     9,356,948              8,252,522
                                                            ----------------------------------------------

Minority Interest in Subsidiary Companies                                  509,549                230,421
                                                            ----------------------------------------------
Total Liabilities and Capitalization                               $    14,626,784        $    12,980,050
                                                            ==============================================
</TABLE>
        See accompanying Notes to the Consolidated Financial Statements.



                                       90
<PAGE>

<TABLE>
<CAPTION>
                        CONSOLIDATED STATEMENT OF INCOME
-------------------------------------------------------------------------------------------------------------------------
                                                                                        Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts)                           2003              2002              2001
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>                <C>               <C>
Revenues
     Gas Distribution                                                   $ 4,161,272        $ 3,163,761       $ 3,613,551
     Electric Services                                                    1,503,086          1,421,043         1,421,079
     Energy Services                                                        641,432            938,761         1,100,167
     Gas Exploration and Production                                         501,255            357,451           400,031
     Energy Investments                                                     108,116             89,650            98,287
                                                                  -------------------------------------------------------
Total Revenues                                                            6,915,161          5,970,666         6,633,115
                                                                  -------------------------------------------------------
Operating Expenses
     Purchased gas for resale                                             2,495,102          1,653,273         2,171,113
     Fuel and purchased power                                               414,633            395,860           538,532
     Operations and maintenance                                           2,005,796          2,101,897         2,114,759
     Depreciation, depletion and amortization                               574,074            514,613           559,138
     Operating taxes                                                        418,236            381,767           448,924
                                                                  -------------------------------------------------------
Total Operating Expenses                                                  5,907,841          5,047,410         5,832,466
                                                                  -------------------------------------------------------
Gain on sale of property                                                     15,123              4,730                 -
Income from equity investments                                               19,214             14,096            13,129
                                                                  -------------------------------------------------------
Operating Income                                                          1,041,657            942,082           813,778
                                                                  -------------------------------------------------------
Other Income and (Deductions)
     Interest charges                                                      (307,694)          (301,504)         (353,470)
     Sale of subsidiary stock                                                13,356                  -                 -
     Cost of debt redemption                                                (24,094)                 -                 -
     Minority interest                                                      (63,852)           (24,918)          (40,847)
     Other                                                                   42,119             25,169            34,924
                                                                  -------------------------------------------------------
Total Other Income and (Deductions)                                        (340,165)          (301,253)         (359,393)
                                                                  -------------------------------------------------------
Income Taxes
     Current                                                               (104,355)           (24,212)          101,738
     Deferred                                                               381,666            267,691           108,955
                                                                  -------------------------------------------------------
Total Income Taxes                                                          277,311            243,479           210,693
                                                                  -------------------------------------------------------
Earnings from Continuing Operations                                         424,181            397,350           243,692
                                                                  -------------------------------------------------------
Discontinued Operations
    Income (loss) from operations, net of tax                                     -             (3,356)           10,918
    Loss on disposal, net of tax                                                  -            (16,306)          (30,356)
                                                                  -------------------------------------------------------
    Loss from Discontinued Operations                                             -            (19,662)          (19,438)
                                                                  -------------------------------------------------------
Cumulative Change in Accounting Principles, net of tax                      (37,451)                 -                 -
                                                                  -------------------------------------------------------
Net Income                                                                  386,730            377,688           224,254
Preferred stock dividend requirements                                         5,844              5,753             5,904
                                                                  -------------------------------------------------------
Earnings for Common Stock                                               $   380,886        $   371,935       $   218,350
                                                                  =======================================================
Basic Earnings Per Share:
  Continuing Operations, less preferred stock dividends                 $      2.64        $      2.77       $      1.72
  Discontinued Operations                                                         -              (0.14)            (0.14)
  Change in Accounting Principles                                             (0.23)                 -                 -
                                                                  -------------------------------------------------------
Basic Earnings Per Share                                                $      2.41        $      2.63       $      1.58
                                                                  =======================================================
Diluted Earnings Per Share
  Continuing Operations, less preferred stock dividends                 $      2.62        $      2.75       $      1.70
  Discontinued Operations                                                         -              (0.14)            (0.14)
  Change in Accounting Principles                                             (0.23)                 -                 -
                                                                  -------------------------------------------------------
Diluted Earnings Per Share                                              $      2.39        $      2.61       $      1.56
                                                                  =======================================================
Average Common Shares Outstanding (000)                                     158,256            141,263           138,214
Average Common Shares Outstanding - Diluted (000)                           159,232            142,300           139,221
-------------------------------------------------------------------------------------------------------------------------
</TABLE>
        See accompanying Notes to the Consolidated Financial Statements.


                                       91
<PAGE>

<TABLE>
<CAPTION>
                                    CONSOLIDATED STATEMENT OF CASH FLOWS
-------------------------------------------------------------------------------------------------------------------------------
                                                                                              Year Ended December 31,
(In Thousands of Dollars)                                                            2003             2002              2001
-------------------------------------------------------------------------------------------------------------------------------
Operating Activities
<S>                                                                              <C>               <C>               <C>
Net income                                                                     $   386,730       $   377,688       $   224,254
Adjustments to reconcile net income to net
      cash provided by (used in) operating activities
    Depreciation, depletion and amortization                                       574,074           514,613           559,138
    Deferred income tax                                                            189,275            90,724           108,955
    Income from equity investments                                                 (18,038)          (14,096)          (13,129)
    Dividends from equity investments                                                2,807             3,905             7,570
    Amortization of interest rate swap                                              (9,861)                -                 -
    (Gain) loss on disposal of subsidiary stock                                    (13,356)                -            19,438
    Gain on sale of property                                                       (15,123)           (4,730)                -
    Gain from class action settlement                                                    -                 -           (33,510)
    Provision for losses on contracting business                                         -                 -            63,682
   Change in accounting principle                                                   37,451                 -                 -
   Environmental reserve adjustment                                                (10,459)                -                 -
   Minority interest                                                                63,852            24,918            40,847
Changes in assets and liabilities
    Accounts receivable                                                             77,750          (259,454)          401,976
    Materials and supplies, fuel oil and gas in storage                           (199,357)           42,508           (43,856)
    Accounts payable and accrued expenses                                          199,980            18,179          (400,636)
    Reserve payments                                                               (36,486)          (23,369)                -
    Other                                                                          (44,596)          (39,394)          (44,548)
                                                                          -----------------------------------------------------
Net Cash Provided by Operating Activities                                        1,184,643           731,492           890,181
                                                                          -----------------------------------------------------
Investing Activities
    Construction expenditures                                                   (1,011,716)       (1,061,022)       (1,059,759)
    Other Investments                                                             (211,370)          (27,579)                -
    Proceeds from sale of property and subsidiary stock                            309,696           179,840            18,458
    Issuance of long-term note                                                     (55,000)                -                 -
    Other                                                                                -                 -                (6)
                                                                          -----------------------------------------------------
Net Cash (Used in) Investing Activities                                           (968,390)         (908,761)       (1,041,307)
                                                                          -----------------------------------------------------
Financing Activities
    Treasury stock issued                                                           96,687            86,710            88,786
    Common stock issuance                                                          473,573                 -                 -
    Issuance of long-term debt                                                   1,024,912           549,280           812,116
    Payment of long-term debt                                                     (605,625)         (124,991)         (183,410)
    Payment of commercial paper                                                   (433,797)         (132,753)         (251,787)
    Redemption of promissory notes                                                (447,005)                -                 -
    Redemption of preferred stock                                                  (14,293)                -                 -
    Common and preferred stock dividends paid                                     (280,560)         (256,656)         (251,502)
    Termination of interest rate swaps                                                   -            57,415                 -
    Other                                                                            4,989             9,629            12,846
                                                                          -----------------------------------------------------
Net Cash (Used in) Provided by Financing Activities                               (181,119)          188,634           227,049
                                                                          -----------------------------------------------------
Net Increase in Cash and Cash Equivalents                                      $    35,134       $    11,365       $    75,923
Cash and Cash Equivalents at Beginning of Period                                   170,617           159,252            83,329
                                                                          -----------------------------------------------------
Cash and Cash Equivalents at End of Period                                     $   205,751       $   170,617       $   159,252
                                                                          =====================================================
Interest Paid                                                                  $   355,136       $   343,933       $   328,910
Income Tax Paid                                                                $    65,495       $    98,344       $   128,558
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>
        See accompanying Notes to the Consolidated Financial Statements.


                                       92
<PAGE>

<TABLE>
                   CONSOLIDATED STATEMENT OF RETAINED EARNINGS
<CAPTION>
--------------------------------------------------------------------------------------------------------
                                                                        Year Ended December 31,
(In Thousands of Dollars)                                       2003            2002              2001
--------------------------------------------------------------------------------------------------------
<S>                                                          <C>              <C>              <C>
Balance at Beginning of Period                               $522,835         $452,206         $480,639
Net Income for Period                                         386,730          377,688          224,254
--------------------------------------------------------------------------------------------------------
                                                              909,565          829,894          704,893
Deductions:
Cash dividends declared on common stock                       282,291          252,175          246,783
Cash dividends declared on preferred stock                      5,844            5,753            5,904
MEDS Equity Units                                                   -           49,131                -
--------------------------------------------------------------------------------------------------------
Balance at End of Period                                     $621,430         $522,835         $452,206
--------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
                 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                                                                                               Year Ended December 31,
(In Thousands of Dollars)                                                                2003            2002           2001
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>            <C>             <C>
Net Income                                                                           $ 386,730       $ 377,688      $ 224,254
------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income, net of tax
Net losses (gains) on derivative instruments                                            23,042         (17,033)       (27,690)
Reclassification adjustment for other gains reclassified to net income                       -               -         (3,242)
Foreign currency translation adjustments                                                28,696           9,759         (9,627)
Unrealized gains (losses) on marketable securities                                       8,480         (10,019)        (5,464)
Premium on derivative instrument                                                        (3,437)              -              -
Accrued unfunded pension obligation                                                      8,380         (55,768)       (13,262)
Unrealized (losses) gains on derivative financial instruments                          (25,379)        (39,845)        62,943
------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax                                           39,782        (112,906)         3,658
------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income                                                                 $ 426,512       $ 264,782      $ 227,912
------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Net losses (gains) on derivative instruments                                            12,407          (9,172)     $ (14,910)
Reclassification adjustment for other gains reclassified to net income                       -               -         (1,746)
Foreign currency translation adjustments                                                15,451           5,255         (5,184)
Unrealized gains (losses) on marketable securities                                       4,568          (5,395)        (2,942)
Accrued unfunded pension obligation                                                      4,513         (30,029)        (7,140)
Premium on derivative instrument                                                        (1,851)              -              -
Unrealized (losses) gains on derivative financial instruments                          (13,666)        (21,454)        33,892
------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense                                                          $  21,422       $ (60,795)     $   1,970
------------------------------------------------------------------------------------------------------------------------------
</TABLE>
        See accompanying Notes to the Consolidated Financial Statements.


                                       93
<PAGE>

<TABLE>
                    CONSOLIDATED STATEMENT OF CAPITALIZATION
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                                            December 31,
(In Thousands of Dollars)                                          2003              2002                  2003              2002
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>                <C>                   <C>               <C>
Common Shareholders' Equity                                            Shares Issued
Common stock, $0.01 par Value                                  172,737,654        158,837,654         $     1,727       $     1,588
Premium on capital stock                                                                                3,485,918         3,003,766
Retained earnings                                                                                         621,430           522,835
Other comprehensive income                                                                                (68,640)         (108,423)
Treasury stock                                                  13,073,219         16,412,880            (378,487)         (475,174)
------------------------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity                              159,664,435        142,424,774           3,661,948         2,944,592
------------------------------------------------------------------------------------------------------------------------------------

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                                    85,676             88,486               8,568             8,849
------------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required                                                             83,568            83,849
------------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt                                          Interest Rate           Maturity
------------------------------------------------------------------------------------------------------------------------------------
Notes
Medium term notes                                         4.65% - 9.75%         2005 - 2033             3,185,000         2,885,000
Senior secured notes                                      5.42% - 6.16%          2008-2013                 96,425                 -
Senior subordinated notes                                      7.0%                2013                   175,000           100,000
------------------------------------------------------------------------------------------------------------------------------------
Total Notes                                                                                             3,456,425         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
Pollution control revenue bonds                               5.15%                2016                   108,022           108,022
Electric facilities revenue bonds                             5.30%             2023 - 2025                47,400           224,405
------------------------------------------------------------------------------------------------------------------------------------
Total Promissory Notes to LIPA                                                                            155,422           602,427
------------------------------------------------------------------------------------------------------------------------------------

MEDS Equity Units                                             8.75%                2005                   460,000           460,000
Industrial Development Bonds                                  5.25%                2027                   128,275                 -
First Mortgage Bonds                                     5.50% - 10.10%         2003 - 2028               153,186           163,625
Authority Financing Notes                                   Variable            2027 - 2028                66,005            66,005
Other Subsidiary Debt                                                                                     145,612           304,298
Ravenswood Master Lease & Capital Leases                                        2005 - 2022               425,262            13,884
------------------------------------------------------------------------------------------------------------------------------------
Subtotal                                                                                                5,638,687         5,243,739
Unamortized interest rate hedge and debt discount                                                         (69,243)          (75,265)
Derivative impact on debt                                                                                  43,459            67,020
Less: current maturities                                                                                    1,471            11,413
------------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt                                                                                    5,611,432         5,224,081
------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                                                                  $ 9,356,948       $ 8,252,522
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
        See accompanying Notes to the Consolidated Financial Statements.


                                       94
<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 1.0 million electric  customers of the Long Island Power Authority
("LIPA").

Our other  subsidiaries  are involved in gas and oil exploration and production;
gas  storage;  liquefied  natural gas  storage;  wholesale  and retail  electric
marketing;  appliance service; plumbing; heating,  ventilation, air conditioning
and other mechanical services; large energy-system  ownership,  installation and
management;  fiber optic services;  and engineering and consulting services.  We
also invest in, 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.)

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


                                       95
<PAGE>

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.

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.  Certain  reclassifications  were made to conform prior period
financial  statements to current period financial  statement  presentation.  For
December 31, 2003, 2002 and 2001, we reclassified income from equity investments
and property sales from other income and (deductions) to operating income on the
Consolidated  Statement of Income.  On the 2001  Consolidated  Statement of Cash
Flows,  "minority  interest",  "changes in assets and liabilities - other",  and
"(gain) loss on disposal of subsidiary  stock"  amounts have been  reclassified.
The amount related to the loss from discontinued  operations has been separately
identified  as "(gain)  loss on  disposal of  subsidiary  stock".  In  addition,
"minority  interest"  was  previously  disclosed  as a component  of "changes in
assets and  liabilities - other";  it has now been  reclassified  as a separate
line item for all periods presented.

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.


                                       96
<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  ten-year  periods,  ending 2009 and 2008,  respectively.  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, 2003 and
December 31, 2002.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
                                                                                       December 31,
(In Thousands of Dollars)                                                        2003                2002
------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>                 <C>
Regulatory Assets
Regulatory tax asset                                                          $  47,236           $  53,401
Property taxes                                                                   64,854              58,400
Environmental costs                                                             296,888             182,163
Postretirement benefits                                                          93,284              82,563
Costs associated with the KeySpan/LILCO transaction                              50,585              61,989
Derivative Financial Instruments                                                  6,909                   -
Other                                                                             5,229                   -
------------------------------------------------------------------------------------------------------------
Total Regulatory Assets                                                       $ 564,985           $ 438,516
Miscellaneous Regulatory Liabilities                                           (104,034)            (84,479)
------------------------------------------------------------------------------------------------------------
Net Regulatory Assets                                                           460,951             354,037

Removal Costs Recovered                                                        (450,034)                  -
------------------------------------------------------------------------------------------------------------
                                                                              $  10,917           $ 354,037
------------------------------------------------------------------------------------------------------------
</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 $53.4  million and $61.8  million at December 31, 2003 and December
31, 2002,  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 10
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


                                       97
<PAGE>


Discontinuation  of  Application  of FASB  Statement  71." We estimate  that the
write-off  of  all  net   regulatory   assets  at  December  31,  2003,   before
consideration of removal costs recovered, could result in a charge to net income
of  $300  million  or  $1.89  per  share,   which  would  be  classified  as  an
extraordinary  item. In 2003, KeySpan implemented SFAS 143 "Accounting for Asset
Retirement   Obligations"  and  reclassified   cost  of  removal  accruals  from
accumulated  depreciation to regulatory  liabilities.  For the 2002 Consolidated
Balance Sheet presentation, these accruals are reflected as a separate line item
in  deferred  credits  and  other  liabilities.  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.

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.

KeySpan manages the day-to-day operations,  maintenance and capital improvements
of the T&D system under a Management Service Agreement ("MSA").  In exchange for
providing  the  services,  KeySpan earns a $10 million  annual  management  fee.
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.


                                       98
<PAGE>


In addition, KeySpan sells to LIPA under a Power Supply Agreement ("PSA") 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. Rates charged to LIPA include a fixed and variable component. The variable
component  is  billed  to LIPA on a  monthly  per  megawatt  hour  basis  and is
dependent  on  the  number  of  megawatt  hours  dispatched.  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.

KeySpan  also  procures and manages  fuel  supplies on behalf of LIPA,  under an
Energy Management  Agreement  ("EMA"),  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.

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. Each plant is 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.)
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 derived from service  rendered  under fixed
price,  cost-plus,   guaranteed  maximum  price,  and  time  and  materials-type
contracts  and  generally  recognized  on the  percentage-of-completion  method.
Percentage-of-completion  is measured  principally  by 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.  In the case of
customer change orders,  estimated recoveries are included for work performed in
forecasting  ultimate  profitability on certain contracts.  Due to uncertainties
inherent in the estimation process, changes in job performance,  job conditions,
estimated  profitability and final contract  settlements may result in revisions
to estimated costs and, therefore,  revenues. Such revisions to costs and income
are recognized in the period in which the revisions are determined.


                                       99
<PAGE>


Costs and  estimated  earnings in excess of billings  on  uncompleted  contracts
arise when revenues  have been  recorded but the amounts  cannot be billed under
the terms of the  contracts.  Such amounts are  recoverable  from customers upon
various measures of performance,  including  achievement of certain  milestones,
completion of specified units or completion of the contract.

Also  included in costs and  estimated  earnings on  uncompleted  contracts  are
amounts to be collected from customers for changes in contract specifications or
design, contract change orders in dispute or unapproved as to scope or price, or
other customer-related causes of unanticipated  additional contract costs. These
amounts are recorded at their estimated net realizable value when realization is
probable and can be reasonably  estimated.  Claims and unapproved  change orders
involve negotiation and, in certain cases, litigation.  Unapproved change orders
and claims also involve the use of estimates, and it is reasonably possible that
revisions to the  estimated  recoverable  amounts of recorded  change orders and
claims may be made in the near-term.  If KeySpan does not  successfully  resolve
these matters, an expense may be required, in addition to amounts that have been
previously  provided for.  Claims against  KeySpan are recognized when a loss is
considered probable and amounts are reasonably determinable.

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
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 $23.8 million and $19.2 million for the
years ended  December 31, 2003,  and  December  31,  2002,  respectively.  These
balances represent  primarily unearned revenues for service contracts and leases
on 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 five to 30 years.

Gas Exploration  and Production:  Natural gas and oil revenues earned by our gas
exploration  and production  activities are  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.

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 the years ended December 31, 2001 through
2003 ranged from 2.95% to 10.67%.  Capitalized  interest for 2003, 2002 and 2001
was $13.5 million, $19.7 million and $8.5 million, respectively.


                                       100
<PAGE>


Depreciation  is  provided on a  straight-line  basis in amounts  equivalent  to
composite rates on average depreciable property. The cost of property retired is
charged to accumulated depreciation.

KeySpan  recovers  certain  asset  retirement  costs  through  rates  charged to
customers as a portion of depreciation  expense.  At December 31, 2003 and 2002,
KeySpan had costs  recovered in excess of costs  incurred  totaling $450 million
and $366  million,  respectively.  These  amounts are  reflected as a regulatory
liability for 2003 and in deferred credits and other liabilities for 2002 on the
Consolidated Balance Sheet.

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,
                                     2003           2002            2001
--------------------------------------------------------------------------
Electric                             3.81%           3.88%          3.78%
Gas                                  3.37%           3.44%          3.40%
--------------------------------------------------------------------------


We also had $425.6 million of other property at December 31, 2003,  which is not
reflected  in "rate  base" for  utility  rate  making  purposes.  This  property
consists of assets held primarily by our Corporate Service  subsidiary of $320.3
million and $105.3  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. We allocate the carrying
cost of these assets to our operating  subsidiaries through our PUHCA allocation
methodology.  Energy Services  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  unless they represent  replacement  of property to be  capitalized.
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, 2003, we had exploration  and production  property in the amount
of $3.1 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 depletion
and  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.


                                       101
<PAGE>


These  investments  consist  of  our  55%  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
("KeySpan Exploration"),  our wholly-owned subsidiary engaged in a joint venture
with  Houston  Exploration.  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,  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,  2003,  we  estimated,  using a
wellhead price of $5.79 per MCF, that our  capitalized  costs did not exceed the
ceiling test  limitation.  At December 31, 2002, we estimated,  using a wellhead
price of $4.35 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,  a $42.0  million
impairment  charge to write down our gas exploration  and production  assets was
recorded.  This charge was recorded in depreciation,  depletion and amortization
on the  Consolidated  Statement  of Income.  KeySpan's  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 a write down to the
full cost pool  increases  when,  among  other  things,  natural  gas prices are
depressed,  there are  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  amortized.  For years ended December 31, 2003,  2002 and 2001,
capitalized  interest  was  $7.3  million,   $8.0  million  and  $12.0  million,
respectively.


                                      102
<PAGE>


G.  Goodwill and Other Intangible Assets

The balance of goodwill and other intangible assets was $1.8 billion at December
31, 2003 and 2002,  representing  primarily the excess of acquisition  cost over
the fair value of net assets  acquired.  Goodwill  and other  intangible  assets
reflect the Eastern and ENI acquisitions, the KeySpan/LILCO transaction, as well
as acquisitions of energy-related  service companies and also relates to certain
ownership  interests of 50% or less in  energy-related  investments  in Northern
Ireland which are accounted for under the equity method.

The table below summarizes the goodwill and other intangible assets balance for
each segment at December 31, 2003 and 2002:

----------------------------------------------------------------------------
(In Thousands of Dollars)                         Year Ended December 31,
----------------------------------------------------------------------------
Operating Segment                                 2003              2002

Gas Distribution                               $1,436,917        $1,436,917
Energy Services                                   172,874           148,596
Energy Investments and other                      199,921           210,712
----------------------------------------------------------------------------
                                               $1,809,712        $1,796,225
----------------------------------------------------------------------------

The  increase  in  goodwill  related to the Energy  Services  segment  primarily
reflects the  acquisition  of Bard,  Rao + Athanas  Consulting  Engineers,  LLC.
("BR+A"), a Boston,  Massachusetts  company engaged in the business of providing
engineering  services  relating to heating,  ventilation,  and air  conditioning
systems.  The purchase  price was  approximately  $35 million,  plus up to $14.7
million in contingent  consideration  depending on the financial  performance of
BR+A over the five-year period following the closing of the acquisition. We have
recorded  goodwill  of  approximately  $26  million  and  intangible  assets  of
approximately  $2  million  associated  with this  transaction.  The  intangible
assets, which relate primarily to a portion of the backlog purchased, as well as
to  non-compete  agreements  entered into with all of the former owners of BR+A,
will be amortized over two and three years, respectively.

The  decrease  in goodwill  related to Energy  Investments  and other  primarily
reflects the sale of our 24.5% interest in Phoenix Natural Gas Limited,  located
in Northern Ireland,  and the related write-off of the goodwill  associated with
this investment.

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
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. 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.


                                      103
<PAGE>


In the fourth quarter of 2003,  KeySpan updated its review of the carrying value
of goodwill  associated with the Energy  Services  segment.  KeySpan  employed a
combination  of  two  methodologies  in  determining  the  fair  value  for  its
investment in the Energy Services  segment,  a market valuation  approach and an
income valuation  approach.  A third party specialist was engaged to assist with
the valuation and evaluate the reasonableness of key assumptions employed. Under
the market valuation approach,  KeySpan compared relevant financial  information
relating  to the  companies  included  in the  Energy  Services  segment  to the
corresponding  financial  information  for a  peer  group  of  companies  in the
specialty  trade-contracting  sector  of the  construction  industry.  Under the
income valuation  approach,  the fair value of a firm is obtained by discounting
the sum of (i) the expected  future cash flows to a firm;  and (ii) the terminal
value of a firm. As a result of our valuation,  management  has determined  that
the fair value of the assets  adequately  exceeds  their  carrying  value and no
impairment charge was necessary.

As  required  by SFAS  142,  below  is a  reconciliation  of  reported  earnings
available for common  stockholders  for the years ended December 31, 2003,  2002
and 2001 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)                       2003              2002             2001
------------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                <C>              <C>
Earnings  for common stockholders                                         $ 380,886          $ 371,935        $ 218,350
Add back: goodwill amortization*                                                  -                  -           49,550
------------------------------------------------------------------------------------------------------------------------
Adjusted net income                                                       $ 380,886          $ 371,935        $ 267,900
------------------------------------------------------------------------------------------------------------------------
Basic earnings per share                                                  $    2.41          $    2.63        $    1.58
Add back: goodwill amortization                                                   -                  -             0.36
------------------------------------------------------------------------------------------------------------------------
Adjusted basic earnings per share                                         $    2.41          $    2.63        $    1.94
------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share                                                $    2.39          $    2.61        $    1.56
Add back: goodwill amortization                                                   -                  -             0.36
------------------------------------------------------------------------------------------------------------------------
Adjusted diluted earnings per share                                       $    2.39          $    2.61        $    1.92
------------------------------------------------------------------------------------------------------------------------
</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,  goodwill  amortization  was
recorded in each segment as follows:  Gas  Distribution  $35.6  million;  Energy
Services $8.2 million; and Energy Investments and other $5.8 million.

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 was
reviewed if the facts and circumstances,  such as significant declines in sales,
earnings or cash flows,  or material  adverse  changes in the business  climate,
suggested it might be impaired.  If this review  indicated that goodwill was not
recoverable,  as determined based upon the estimated  undiscounted cash flows of
the entity acquired,  impairment was measured by comparing the carrying value of
the investment in such entity to its fair value. Fair value was 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.)


                                      104
<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-related  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  149,
"Amendment  of Statement  133  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.  Unrealized  gains and losses (on such cash flow  hedges) that are
recorded  as other  comprehensive  income  are  subsequently  reclassified  into
earnings concurrent 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 England  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  regulatory  assets or  regulatory
liabilities 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.


                                      105
<PAGE>


Physically-Settled  Commodity  Derivative  Instruments:  Upon  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
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
Emerging Issues Task Force ("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 our cost of capital, 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.


                                      106
<PAGE>


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, 2003, 2002
and 2001,  excise taxes  collected and paid were $90.5  million,  $83.1 million,
$119.1 million, respectively.

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, 2003 and 2002, the foreign currency
translation  adjustment  was included 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, 2003 we have  approximately  2 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
85,676 shares of convertible  preferred stock  outstanding that can be converted
into  221,153  shares of common  stock.  These  shares were not  included in the
calculation of diluted EPS for the year ending  December 31, 2001 since to do so
would have been anti-dilutive.


                                      107
<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)                                    2003             2002             2001
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>               <C>              <C>
Earnings for common stock                                                          $ 380,886         $ 371,935        $ 218,350
Houston Exploration dilution                                                            (269)             (471)          (1,116)
Preferred stock dividend                                                                 514               531                -
--------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted                                               $ 381,131         $ 371,995        $ 217,234
--------------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000)                                            158,256           141,263          138,214
Add dilutive securities:
Options                                                                                  755               809            1,007
Convertible preferred stock                                                              221               228                -
--------------------------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution                        159,232           142,300          139,221
--------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share                                                           $    2.41         $    2.63        $    1.58
--------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share                                                         $    2.39         $    2.61        $    1.56
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>

N.  Stock Options and Other Stock Based Compensation

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 exercise  periods between 5-10 years.
Up to  approximately  21 million shares have been authorized for the issuance of
options and approximately 7.0 million of these shares were remaining at December
31, 2003.  Moreover,  under a separate plan, Houston  Exploration has issued and
outstanding  approximately 2.5 million stock options to key Houston  Exploration
employees.  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 has
been recognized by employing the fair value  recognition  provisions of SFAS 123
"Accounting  for Stock-Based  Compensation"  for grants awarded after January 1,
2003.

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


                                      108
<PAGE>


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                                                                                            Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts)                               2003               2002              2001
------------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock:
<S>                                                                             <C>               <C>                <C>
As reported                                                                    $ 380,886         $ 371,935          $ 218,350
     Add: recorded stock-based compensation expense, net of tax                    3,650               221                261
     Deduct: total stock-based compensation expense, net of tax                   (9,358)           (7,547)            (8,459)
------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings                                                             $ 375,178         $ 364,609          $ 210,152
------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
     Basic - as reported                                                       $    2.41         $    2.63          $    1.58
     Basic - pro-forma                                                         $    2.37         $    2.58          $    1.52

     Diluted - as reported                                                     $    2.39         $    2.61          $    1.56
     Diluted - pro-forma                                                       $    2.36         $    2.56          $    1.50
------------------------------------------------------------------------------------------------------------------------------
</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,
                                                 2003                 2002                2001
-------------------------------------------------------------------------------------------------
<S>                                           <C>                 <C>                  <C>
Fair value of grants issued                 $    4.26           $     3.42           $     5.29
Dividend yield                                   5.49%                5.36%                4.91%
Expected volatility                             24.26%               22.47%               29.04%
Risk free rate                                   3.16%                4.94%                5.13%
Expected lives                                 6 years             10 years             10 years
Exercise price                              $    32.40          $     32.66          $     39.50
-------------------------------------------------------------------------------------------------
</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,
                                                    2003                          2002                              2001
------------------------------------------------------------------------------------------------------------------------------------
                                                          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       9,524,900        $ 30.74        7,796,162         $ 29.67         6,456,627        $ 25.61
Granted during the year                  1,650,450        $ 32.40        2,796,310         $ 32.66         2,285,350        $ 39.50
Exercised                                 (664,902)       $ 23.64         (506,794)        $ 24.42          (809,983)       $ 25.15
Forfeited                                 (189,705)       $ 34.63         (560,778)        $ 30.99          (135,832)       $ 29.19
------------------------------------------------------------------------------------------------------------------------------------
Outstanding at end of period            10,320,743        $ 31.39        9,524,900         $ 30.74         7,796,162        $ 29.67
------------------------------------------------------------------------------------------------------------------------------------
Exercisable at end of period             5,365,545        $ 28.76        4,105,999         $ 27.69         2,996,771        $ 24.86
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      109
<PAGE>


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                      Options            Weighted         Range of              Options             Weighted            Range of
   Remaining        Outstanding at        Average         Exercise            Exercisable at         Average            Exercise
Contractual Life   December 31, 2003    Exercise Price     Price            December 31,2003      Exercise Price          Price
------------------------------------------------------------------------------------------------------------------------------------
<S>                 <C>                    <C>          <C>                   <C>                     <C>            <C>
 2 years                 30,138           $ 25.98       $14.86 - 27.00            30,138             $ 25.98         $14.86 - 27.00
 3 years                221,086           $ 30.43       $20.57 - 30.50           221,086             $ 30.43         $20.57 - 30.50
 4 years                301,410           $ 32.56       $19.15 - 32.63           301,410             $ 32.56         $19.15 - 32.63
 5 years              1,359,727           $ 27.86       $24.73 - 29.38         1,359,727             $ 27.86         $24.73 - 29.38
 6 years                652,344           $ 26.97       $21.99 - 27.06           652,344             $ 26.97         $21.99 - 27.06
 7 years              1,567,924           $ 22.79       $22.50 - 32.76         1,546,262             $ 22.64         $22.50 - 32.76
 8 years              2,012,038           $ 39.50           $39.50               805,553             $ 39.50             $39.50
 9 years              2,565,404           $ 32.66           $32.66               449,025             $ 32.66             $32.66
 10 years             1,610,672           $ 32.40           $32.40                     -             $ 32.40             $32.40
------------------------------------------------------------------------------------------------------------------------------------
                     10,320,743                                                5,365,545
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

In early 2003,  KeySpan's  Board of  Directors  approved a  modification  to the
Long-Term Incentive  Compensation Plan design and its application to officers of
KeySpan.  Long-term  incentive  compensation  for officers  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

In January 2003, the Financial  Accounting  Standards Board ("FASB") issued FASB
Interpretation No. 46 ("FIN 46"),  "Consolidation of Variable Interest Entities,
an  Interpretation  of ARB No. 51" which was  revised in December  2003.  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 was effective for all
new variable  interest  entities created or acquired after January 31, 2003. For
variable  interest  entities  created or acquired prior to February 1, 2003, the
original provisions of FIN 46 were to be applied for the first interim or annual
period   beginning   after  June  15,  2003.   In  October,   the  FASB  delayed
implementation  of FIN 46 until the fourth  quarter  2003 for  certain  variable
interest  entities.  We currently have an arrangement  with a variable  interest
entity through which we lease a portion of the Ravenswood facility.  As required
by FIN 46, this variable entity was consolidated at December 31, 2003. (See Note
7 "Contractual  Obligations,  Financial  Guarantees and Contingencies - Variable
Interest Entity" for a detailed description of this leasing arrangement.)

In April  2003,  the FASB  issued  SFAS  149,  "Amendment  of  Statement  133 on
Derivative  Instruments  and  Hedging  Activities."  This  Statement  amends and
clarifies  financial  accounting  and  reporting  for  derivative   instruments,
including  certain  instruments  embedded  in other  contracts  and for  hedging
activities under Statement No. 133,  "Accounting for Derivative  Instruments and
Hedging  Activities." This Statement:  (i) clarifies under what  circumstances a
contract  with  an  initial  net  investment  meets  the   characteristic  of  a
derivative;  (ii)  clarifies when a derivative  contains a financing  component;
(iii) amends the  definition  of an  underlying;  and (iv) amends  certain other
existing  pronouncements.  The  implementation of this Statement will not have a
significant  impact on our results of  operations,  financial  condition or cash
flows since our derivative  instruments that meet the definition of a derivative
and qualify for hedge accounting treatment will continue to do so. The Statement
was effective for contracts entered into or modified after June 30, 2003.


                                      110
<PAGE>


In May  2003,  the FASB  issued  SFAS 150,  "Accounting  for  Certain  Financial
Instruments with Characteristics of Both Liabilities and Equity." This Statement
establishes  standards  for  how  an  issuer  classifies  and  measures  certain
financial  instruments with  characteristics  of both liabilities and equity. It
requires that an issuer classify  certain  financial  instruments as a liability
(or an asset in some  circumstances)  when there is an  obligation to redeem the
issuer's  shares  and  either  requires  or  may  require  satisfaction  of  the
obligation  by  transferring  assets,  or  satisfy  the  obligation  by  issuing
additional  equity  shares  subject  to certain  criteria.  This  Statement  was
effective for financial instruments entered into or modified after May 31, 2003,
and  otherwise  was  effective  at the  beginning  of the first  interim  period
beginning  after  June  15,  2003.  It is to be  implemented  by  reporting  the
cumulative  effect  of  a  change  in  an  accounting  principle  for  financial
instruments created before the issuance date of the Statement and still existing
at the beginning of the interim period of adoption.  The  implementation of this
Statement  did not  have an  impact  on our  results  of  operations,  financial
condition or cash flows.

In July 2003,  the FASB  concluded  its  discussions  on EITF  03-11  "Reporting
Realized  Gains and Losses on  Derivative  Instruments  That Are Subject to FASB
Statement No. 133 Accounting for Derivative  Instruments and Hedging  Activities
and Not Held for  Trading  Purposes  as Defined in EITF  Issue No.  02-3  Issues
Involved in Accounting  for Derivative  Contracts held for Trading  Purposes and
Contracts  Involved in Energy Trading and Risk Management  Activities." The Task
Force reached a consensus that  determining  whether realized gains or losses on
physically settled  derivative  contracts not "held for trading purposes" should
be  reported  in the  income  statement  on a gross or net  basis is a matter of
judgment that depends on the relevant facts and  circumstances.  KeySpan reports
realized gains or losses on its derivative  instruments that hedge the cash flow
variability  associated with the forecasted sales of natural gas and electricity
in its reported revenues at time of their  settlement.  Realized gains or losses
on derivative  instruments that hedge the cash flow variability  associated with
the  forecasted  purchase of natural gas or fuel oil are  reported in  operating
expense.  We believe  that this EITF does not have a  significant  impact on our
results of  operations,  financial  condition or cash flows.  This Statement was
effective October 1, 2003.

In  December  2003,  the  FASB  issued  SFAS  132  (revised  2003)   "Employers'
Disclosures  about Pensions and Other  Postretirement  Benefits." This Statement
revises employers'  disclosures about pension and other  postretirement  benefit
plans.  This  Statement  retains the disclosure  requirements  contained in FASB
Statement 132 "Employers'  Disclosures  about Pensions and Other  Postretirement
Benefits", which it replaces. It requires additional disclosures to those in the
original Statement 132 about assets,  obligations,  cash flows, and net periodic
benefit  cost of  defined  benefit  pension  plans  and  other  defined  benefit
postretirement  plans.  KeySpan has  implemented  all the  requirements  of this
Statement in Footnote 4 "Postretirement Benefits."

P. Impact of Cumulative Effect of Change in Accounting Principles

KeySpan has an  arrangement  with a variable  interest  entity  through which it
leases a portion of the 2,200-megawatt  Ravenswood electric generation facility.
On December  31,  2003,  KeySpan  adopted FIN 46.  This  pronouncement  required
KeySpan to consolidate  its variable  interest  entity,  which had a fair market
value of a $425 million at the  inception of the lease,  June 1999. As a result,
KeySpan recorded a $37.6 million after-tax charge, or $0.23 per share, change in
accounting  principle  on the  Consolidated  Statement  of Income,  representing
approximately  four and a half years of depreciation.  (See Note 7, "Contractual
Obligations,  Financial Guarantees and Contingencies - Variable Interest Entity"
for a detailed description of the impact of the adoption of this standard.)


                                      111

<PAGE>

On January 1, 2003,  KeySpan adopted 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.  The cumulative
effect of SFAS 143 and the change in  accounting  principle was a benefit to net
income  of $0.2  million,  after-tax.  (See  Note 7,  "Contractual  Obligations,
Financial  Guarantees  and  Contingencies  - Asset  Retirement  Obligation"  for
further details.)

Under Accounting Principle Board Opinion No. 20 ("APB 20"), the pro-forma impact
of the  retroactive  application  resulting  from the  adoption  of a change  in
accounting principle is to be disclosed as follows:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                                                                            Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts)                            2003                   2002                  2001
----------------------------------------------------------------------------------------------------------------------------------

<S>                                                                          <C>                  <C>                   <C>
Earnings for common stock                                                   $ 380,886             $ 371,935             $ 218,350
Add back: Cumulative effect of a change in accounting principle                37,451                     -                     -
Earnings for common stock before cumulative effect of a change in
accounting principle:
As reported                                                                   418,337               371,935               218,350
     Less: SFAS 143 Accretion expense, net of taxes                                 -                (1,135)               (1,067)
     Less:FIN 46  Depreciation expense, net of taxes                           (9,538)               (8,024)               (8,024)
     Add: SFAS 143 Costs of removal expense, net of taxes                           -                   471                   471
----------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings                                                          $ 408,799             $ 363,247             $ 209,730
----------------------------------------------------------------------------------------------------------------------------------


Earnings per share before cumulative change in accounting principle:
     Basic - as reported                                                    $    2.64              $   2.63              $   1.58
     Basic - pro-forma                                                      $    2.58              $   2.57              $   1.52

     Diluted - as reported                                                  $    2.62              $   2.61              $   1.56
     Diluted - pro-forma                                                    $    2.57              $   2.55              $   1.51
----------------------------------------------------------------------------------------------------------------------------------

Earnings per share for common stock:
     Basic - as reported                                                    $    2.41              $   2.63              $   1.58
     Basic - pro-forma                                                      $    2.58              $   2.57              $   1.52

     Diluted - as reported                                                  $    2.39              $   2.61              $   1.56
     Diluted - pro-forma                                                    $    2.57              $   2.55              $   1.51
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

Q.          Accumulated Other Comprehensive Income

As required by SFAS 130,  "Reporting  Comprehensive  Income",  the components of
accumulated other comprehensive income are as follows:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
                                                                    Year Ended December 31,
(In Thousands of Dollars)                                           2003               2002
---------------------------------------------------------------------------------------------
<S>                                                              <C>                <C>
Foreign currency translation adjustments                         $ 26,523           $ (2,173)
Unrealized (losses) on marketable securities                       (7,530)           (16,012)
Premium on derivative instrument                                   (3,437)                 -
Accrued unfunded pension obligation                               (60,650)           (69,031)
Unrealized (losses) on derivative financial instruments           (23,546)           (21,207)
---------------------------------------------------------------------------------------------
Accumulated other comprehensive income                           $(68,640)        $ (108,423)
---------------------------------------------------------------------------------------------
</TABLE>


                                      112
<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 three to eleven years
and Power Purchase  agreements for 25 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.  KeySpan  is  currently  analyzing  proposals  from
interested  investors to participate in a leveraged lease financing of a new 250
MW  combined  cycle  electric   generating  facility  located  at  the  existing
Ravenswood  facility  site.  (See  Note  15,  "Subsequent  Events"  for  further
details.)

The Energy Services segment includes companies that provide energy-related and a
minimal amount of fiber optic services to customers primarily located within the
Northeastern   United  States,   with   concentrations  in  the  New  York  City
metropolitan  area,  including  New  Jersey  and  Connecticut,  as well as Rhode
Island,  Pennsylvania,  Massachusetts  and New Hampshire,  through the following
lines  of  business:  (i)  Home  Energy  Services,  which  provides  residential
customers with service and maintenance of energy systems and appliances, as well
as the  retail  marketing  of  electricity  to  commercial  customers;  and (ii)
Business  Solutions,  which  provides  plumbing,   heating,   ventilation,   air
conditioning  and  mechanical  services,  as well as operation and  maintenance,
design,  engineering  and  consulting  services  to  commercial  and  industrial
customers.

In  2003,  KeySpan  Services,  Inc.  and  its  wholly-owned  subsidiary  Paulus,
Sokolowski,  and Sartor, LLC. acquired Bard, Rao + Athanas Consulting Engineers,
LLC.  ("BR+A"),  a Boston,  Massachusetts  company  engaged in the  business  of
providing  engineering  services  relating  to  heating,  ventilation,  and  air
conditioning  systems. The purchase price was approximately $35 million, plus up
to  $14.7  million  in  contingent  consideration  depending  on  the  financial
performance  of BR+A over the  five-year  period  following  the  closing of the
acquisition.  We have recorded  goodwill of $26 million and intangible assets of
$2 million associated with this transaction. The intangible assets, which relate
primarily  to a portion  of the  backlog  purchased,  as well as to  non-compete


                                      113
<PAGE>


agreements entered into with all of the former owners of BR+A, will be amortized
over two and three  years,  respectively.  In 2003,  KeySpan's  gas and electric
marketing subsidiary, KeySpan Energy Services Inc., assigned the majority of its
retail  natural  gas  customers,  consisting  mostly  of  residential  and small
commercial  customers,  to ECONnergy  Energy Co.,  Inc.  ("ECONnergy").  KeySpan
Energy Services will continue its electric marketing activities.

The Energy  Investments  segment  consists of our gas exploration and production
investments, as well as certain other domestic and international  energy-related
investments.  Our gas exploration and production subsidiaries are engaged in gas
and oil  exploration  and  production,  and the  development  and acquisition of
domestic natural gas and oil properties.  These  investments  consist of our 55%
equity interest in The Houston Exploration Company ("Houston  Exploration"),  an
independent natural gas and oil exploration company, as well as our wholly-owned
subsidiary KeySpan Exploration and Production,  LLC, our wholly owned subsidiary
engaged in a joint  venture  with  Houston  Exploration.  In February  2003,  we
reduced our ownership interest in Houston  Exploration from 66% to approximately
55% following the repurchase, by Houston Exploration, of three million shares of
common  stock  owned by  KeySpan.  We  realized  net  proceeds of $79 million in
connection with this repurchase.  KeySpan follows an accounting policy of income
statement  recognition  for Parent  company  gains or losses from  common  stock
transactions initiated by its subsidiaries. As a result, KeySpan realized a gain
of $19  million on this  transaction,  which is  reflected  in other  income and
(deductions)  on the  Consolidated  Statement  of Income.  Income taxes were not
provided, since this transaction was structured as a return of capital.

In the fourth quarter of 2003, Houston  Exploration  acquired the entire Gulf of
Mexico shallow-water asset base of Transworld  Exploration and Production,  Inc.
for $149  million.  The  properties,  which are 75%  natural  gas,  have  proven
reserves of 92 billion cubic feet of natural gas equivalent.  Current production
from 11 fields is  approximately 35 million cubic feet of natural gas equivalent
per day.  Houston  Exploration  funded the  transaction  from its bank revolving
credit facility and with cash on hand at the time of closing.

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;  and a 50% interest in the Premier
Transmission  Pipeline  Limited in  Northern  Ireland.  These  subsidiaries  are
accounted  for under the equity  method.  Accordingly,  equity income from these
investments is reflected as a component of operating  income in the Consolidated
Statement of Income. In the fourth quarter of 2003, we completed the sale of our
24.5%  interest in Phoenix  Natural  Gas Limited for $96 million and  recorded a
pre-tax  gain  of  $24.7  million  in  other  income  and  (deductions)  on  the
Consolidated Statement of Income.

We also have  investments  in certain  midstream  natural  gas assets in Western
Canada through  KeySpan  Canada.  These assets include 14 processing  plants and
associated gathering systems that can process  approximately 1.5 BCFe of natural
gas daily and provide associated natural gas liquids fractionation.  In 2003, we
sold a portion of our interest in KeySpan Canada through the establishment of an
open-ended  income fund trust ("KeySpan  Facilities  Income Fund" or the "Fund")
organized  under  the  laws of  Alberta,  Canada.  The  Fund  acquired  a 39.09%
ownership  interest in KeySpan Canada through an indirect  subsidiary,  and then


                                      114
<PAGE>


issued 17 million trust units to the public through an initial public  offering.
Each trust unit  represents a beneficial  interest in the Fund and is registered
on the Toronto Stock Exchange under the symbol KEY.UN. Additionally, we sold our
20% interest in Taylor NGL LP that owns and operates two extraction  plants also
in Canada to AltaGas Services,  Inc. Net proceeds of $119.4 million from the two
sales,  plus proceeds of $45.7  million  drawn under a new credit  facility made
available  to KeySpan  Canada,  were used to pay down  existing  KeySpan  Canada
credit  facilities  of $160.4  million.  A  pre-tax  loss of $30.3  million  was
recognized on the  transactions and is included in other income and (deductions)
on the  Consolidated  Statement  of Income.  These  transactions  produced a tax
expense of $3.8 million as a result of certain  United  States  partnership  tax
rules and  resulted in an after-tax  loss of $34.1  million.  In February  2004,
KeySpan  entered into an agreement to sell an additional  36% of its interest in
KeySpan  Canada.  (See  Note  15  to  the  Consolidated   Financial  Statements,
"Subsequent Events.")

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 operating  income  basis.  Due to the July 2002 sale of Midland
Enterprises LLC, an inland marine barge business, this subsidiary is reported as
discontinued   operations  for  2002  and  2001.  (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          Electric      Energy     Gas Exploration      Other
(In Thousands of Dollars)       Distribution    Services      Services    and Production   Investments   Eliminations   Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
<S>                              <C>           <C>            <C>         <C>               <C>            <C>          <C>
Unaffiliated revenue              4,161,272     1,503,086      641,432       501,255         108,116              -       6,915,161
Intersegment revenue                      -           101        8,158             -           5,008        (13,267)              -
Depreciation, depletion and
 amortization                       259,934        66,843        9,869       204,102          19,046         14,280         574,074
Sales of property                    15,123             -            -             -               -              -          15,123
Income from equity investments            -             -            -             -          19,106            108          19,214
Operating income                    574,254       268,977      (38,066)      197,209          41,345         (2,062)      1,041,657
Interest income                       1,194         4,628        1,070             -           1,002         (2,235)          5,659
Interest charges                    203,733        43,065       16,863         8,504           7,541         27,988         307,694
Total assets                      8,444,071     2,473,076      445,534     1,530,875         915,383        817,845      14,626,784
Equity method investments                 -             -            -             -          97,018              -          97,018
Construction expenditures           419,549       256,498        9,305       295,943          18,154         12,267       1,011,716
------------------------------------------------------------------------------------------------------------------------------------
</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 $1.5 billion for the year
ended  December  31,  2003,  represents  approximately  22% of our  consolidated
revenues during that period.


                                      115
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                    Gas           Electric      Energy    Gas Exploration     Other
(In Thousands of Dollars)        Distribution     Services      Services  and 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
Sales of property                        903         1,479             -            -          2,348              -           4,730
Income from equity investments             -             -             -            -         13,992            104          14,096
Operating income                     531,134       288,796       (11,935)     110,259         32,335         (8,507)        942,082
Interest income                        2,020         1,834         1,248            -            238         (3,768)          1,572
Interest charges                     215,140        57,589        19,386        7,303          6,858         (4,772)        301,504
Total assets                       7,783,011     1,775,244       497,269    1,187,425        974,409        762,692      12,980,050
Equity method investments                  -             -             -            -        130,815              -         130,815
Construction expenditures            412,433       348,147        11,648      241,477         31,243         16,074       1,061,022
------------------------------------------------------------------------------------------------------------------------------------
</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,  2002  represents  approximately  24% of  our  consolidated
revenues during that period.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                    Gas         Electric      Energy     Gas Exploration       Other
(In Thousands of Dollars)       Distribution    Services      Services   and 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
Operating income                     481,393      269,721     (147,485)    159,661            19,122         31,366         813,778
Interest income                        3,879          433        3,185           -               334            495           8,326
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.


                                      116
<PAGE>


Note 3. Income Tax

KeySpan files a consolidated  federal income tax return. A tax sharing agreement
between the 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 return. 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:
------------------------------------------------------------------------------
                                           Year Ended December 31,
(In Thousands of Dollars)          2003              2002               2001
------------------------------------------------------------------------------
Current income tax             $(104,355)        $ (24,212)          $101,738
Deferred income tax              381,666           267,691            108,955
------------------------------------------------------------------------------
Total income tax                $277,311          $243,479           $210,693
------------------------------------------------------------------------------


At December 31, the significant  components of KeySpan's deferred tax assets and
liabilities  calculated  under the  provisions  of SFAS No.109  "Accounting  for
Income Taxes" were as follows:

------------------------------------------------------------------------------
                                                        December 31,
(In Thousands of Dollars)                         2003                   2002
------------------------------------------------------------------------------
Reserves not currently deductible              $ 34,342              $ 38,275
New York corporation income tax                 (56,188)              (13,997)
Property related differences                 (1,049,237)             (818,116)
Regulatory tax asset                            (16,532)              (18,690)
Property taxes                                  (98,089)              (52,339)
Other items - net                               (87,947)              (12,146)
------------------------------------------------------------------------------
Net deferred tax liability                  $(1,273,651)           $ (877,013)
------------------------------------------------------------------------------

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.  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.

The federal  income tax amounts  included in the Statement of Income differ from
the amounts which result from applying the statutory  federal income tax rate to
income before income tax.


                                      117
<PAGE>


The table below sets forth the reasons for such differences:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------
                                                                           Year Ended December 31,
(In Thousands of Dollars)                                     2003                 2002                  2001
---------------------------------------------------------------------------------------------------------------
<S>                                                        <C>                  <C>                   <C>
Computed at the statutory rate                           $  245,522           $  224,290           $   159,035
Adjustments related to:
Tax credits                                                       -               (1,026)               (1,100)
Removal costs                                                (6,592)              (4,787)               (1,470)
Accrual to return adjustment                                    549               (9,539)                2,354
Goodwill amortization                                             -                    -                21,126
Minority interest in Houston Exploration                     19,969                9,490                13,862
State income tax                                             28,462               42,125                26,418
Other items - net                                           (10,599)             (17,074)               (9,532)
---------------------------------------------------------------------------------------------------------------
Total income tax                                         $  277,311           $  243,479           $   210,693
---------------------------------------------------------------------------------------------------------------
Effective income tax rate (1)                                   40%                  38%                   46%
---------------------------------------------------------------------------------------------------------------
</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 and  Boston  Gas  Company  are  subject  to  certain  deferral  accounting
requirements  mandated by the NYPSC and DTE,  respectively for pension costs and
other postretirement benefit costs.

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

<TABLE>
<CAPTION>
The calculation of net periodic pension cost is as follows:
---------------------------------------------------------------------------------------------------------------------------------
                                                                                     Year Ended December 31,
(In Thousands of Dollars)                                                  2003               2002               2001
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>                 <C>                <C>
Service cost, benefits earned during the period                       $   47,531         $   42,423          $   41,162
Interest cost on projected benefit obligation                            138,270            132,424             128,481
Expected return on plan assets                                          (130,556)          (157,958)           (180,757)
Net amortization and deferral                                             66,949             (4,247)            (39,772)
---------------------------------------------------------------------------------------------------------------------------------
Total pension (benefit) cost                                          $  122,194         $   12,642          $  (50,886)
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      118
<PAGE>


The following table sets forth the pension plans' funded status at December 31,
2003 and December 31, 2002.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------
                                                                                            Year Ended December 31,
(In Thousands of Dollars)                                                                 2003                  2002
------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
<S>                                                                                  <C>                    <C>
Benefit obligation at beginning of period                                           $ (2,080,193)          $ (1,915,154)
Service cost                                                                             (47,531)               (42,423)
Interest cost                                                                           (138,270)              (132,424)
Amendments                                                                                (3,079)                (2,932)
Actuarial loss                                                                          (192,617)              (103,988)
Benefits paid                                                                            118,494                116,728
------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                                                   (2,343,196)            (2,080,193)
------------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period                                       1,544,518              1,899,256
Actual return on plan assets                                                             335,757               (347,270)
Employer contribution                                                                     93,458                109,260
Benefits paid                                                                           (118,494)              (116,728)
------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                                             1,855,239              1,544,518
------------------------------------------------------------------------------------------------------------------------
Funded status                                                                           (487,957)              (535,675)
Unrecognized net loss from past experience different from that assumed
 and from changes in assumptions                                                         557,204                627,199
Unrecognized prior service cost                                                           64,925                 71,126
Unrecognized transition obligation                                                             -                    237
------------------------------------------------------------------------------------------------------------------------
Net prepaid pension cost reflected on consolidated balance sheet                    $    134,172           $    162,887
------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                               Year Ended December 31,
                                                       2003             2002             2001
-----------------------------------------------------------------------------------------------
Assumptions:
<S>                                                   <C>              <C>              <C>
Obligation discount                                    6.25%            6.75%            7.00%
Asset return                                           8.50%            8.50%            8.50%
Average annual increase in compensation                4.00%            4.00%            4.00%
-----------------------------------------------------------------------------------------------
</TABLE>

Unfunded  Pension  Obligation:  At  December  31, 2003 the  accumulated  benefit
obligation was in excess of pension assets. As prescribed by SFAS 87 "Employers'
Accounting for  Pensions,"  KeySpan had a $244.4  million  minimum  liability at
December 31, 2003,  for this unfunded  pension  obligation.  As permitted  under
current accounting  guidelines,  these accruals 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 on the Consolidated Balance Sheet.


                                      119
<PAGE>


Therefore,  at year-end,  we had a long-term asset in deferred  charges other of
$55.3 million,  representing the amount of unrecognized prior service cost and a
debit  to  other  comprehensive  income  of  $93.3  million,  or  $60.6  million
after-tax.  The  remaining  amount  of  $95.8  was  recorded  as  a  contractual
receivable,  representing the amount that would have been 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.

At December  31, 2003 the  projected  benefit  obligation,  accumulated  benefit
obligation and value of assets for plans with accumulated benefit obligations in
excess of plan assets were $1.2 billion, $1.1 billion and $794 million.

At December 31, 2002, the accumulated  benefit  obligation was also in excess of
pension assets.  As a result,  we had an additional  minimum liability of $286.3
million,  a long-term  asset in deferred  charges other of $61.5 million,  and a
debit to  other  comprehensive  income  of  $106.2  million,  or  $69.0  million
after-tax.  The  remaining  amount  of  $118.6  was  recorded  as a  contractual
receivable from LIPA.

At December  31, 2002 the  projected  benefit  obligation,  accumulated  benefit
obligation and value of assets for plans with accumulated benefit obligations in
plan assets were $1.1 billion, $948 million and $621 million, respectively.

At the end of the year, we will  re-measure the accumulated  benefit  obligation
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)                                           2003          2002           2001
-------------------------------------------------------------------------------------------------------
<S>                                                              <C>           <C>            <C>
Service cost, benefits earned during the period                  $ 18,825      $ 16,566       $ 20,339
Interest cost on accumulated
   postretirement benefit obligation                               69,803        65,486         64,649
Expected return on plan assets                                    (27,530)      (36,839)       (42,822)
Net amortization and deferral                                      35,815        17,527         11,664
-------------------------------------------------------------------------------------------------------
Other postretirement cost                                        $ 96,913      $ 62,740       $ 53,830
-------------------------------------------------------------------------------------------------------
</TABLE>


                                      120
<PAGE>


The following table sets forth the plans' funded status at December 31, 2003 and
December 31, 2002.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                                                                                           Year Ended December 31,
(In Thousands of Dollars)                                                                 2003                2002
---------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
<S>                                                                                  <C>                   <C>
Benefit obligation at beginning of period                                            $(1,056,944)         $ (969,692)
Service cost                                                                             (18,825)            (16,566)
Interest cost                                                                            (69,803)            (65,486)
Plan participants' contributions                                                          (1,757)             (1,587)
Amendments                                                                                35,458              57,984
Actuarial (loss)                                                                        (209,446)           (115,563)
Benefits paid                                                                             53,693              53,966
---------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                                                   (1,267,624)         (1,056,944)
---------------------------------------------------------------------------------------------------------------------
Change in plan  assets:
Fair value of plan assets at beginning of period                                         361,166             476,146
Actual return on plan assets                                                              85,625             (82,950)
Employer contribution                                                                     43,578              20,349
Plan participants' contributions                                                           1,757               1,587
Benefits paid                                                                            (53,693)            (53,966)
---------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                                               438,433             361,166
---------------------------------------------------------------------------------------------------------------------
Funded status                                                                           (829,191)           (695,778)
Unrecognized net loss from past experience different from that assumed
 and from changes in assumptions                                                         573,277             464,269
Unrecognized prior service cost                                                          (89,034)            (60,104)
---------------------------------------------------------------------------------------------------------------------
Accrued postretirement cost reflected on consolidated balance sheet                  $  (344,948)         $ (291,613)
---------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
                                                             Year Ended December 31,
                                                      2003              2002              2001
------------------------------------------------------------------------------------------------
Assumptions:
<S>                                                  <C>               <C>               <C>
Obligation discount                                   6.25%             6.75%             7.00%
Asset return                                          8.50%             8.50%             8.50%
Average annual increase in compensation               4.00%             4.00%             4.00%
------------------------------------------------------------------------------------------------
</TABLE>

The measurement of plan  liabilities  also assumes a health care cost trend rate
of 11% grading down to 5% over five years,  and 5% 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, 2003 by $149.9
million and the net periodic health care expense by $12.3 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, 2003 by $131.8
million and the net periodic health care expense by $10.5 million.


                                      121
<PAGE>


At December 31, 2003,  KeySpan had a contractual  receivable from LIPA of $226.3
million  representing the postretirement  benefits  associated with the electric
business unit employees  recorded in deferred  charges other on 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.

KeySpan's  retiree health benefit plan  currently  includes a prescription  drug
benefit that is provided to retired  employees.  In December  2003, new Medicare
legislation (the Medicare  Prescription Drug,  Improvement and Modernization Act
of 2003 - "the Medicare Act") was enacted that may ultimately  affect  KeySpan's
obligations and expense related to retiree health benefits.  Keyspan has elected
to defer  accounting  for the effects of the Medicare  Act, as permitted by FASB
Staff Position 106-1  "Accounting  and  Disclosure  Requirements  Related to the
Medicare  Prescription  Drug,   Improvement  and  Modernization  Act  of  2003".
Therefore,  any measure of the accumulated  postretirement benefit obligation or
retiree  benefit costs  reflected in the  accompanying  notes do not reflect the
effects of this new  legislation.  In consideration of this new law, KeySpan may
need to amend certain benefit plans and,  therefore,  the impact of the Medicare
Act on KeySpan's  financial  condition and cash flows can not be determined with
any degree of certainty at this time. Further, the FASB will be issuing specific
guidance on the  accounting  for the subsidy  arising under the Medicare Act and
that guidance,  when issued, could require KeySpan to change previously reported
information.

Pension/Other  Post Retirement  Benefit Plan Assets:  Keyspan's weighted average
asset allocations at December 31, 2003 and 2002, by asset category, for both the
pension and other postretirement benefit plans are as follows:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
                                       Pension                                 OPEB
Asset Category                 2003               2002                2003              2002
---------------------------------------------------------------------------------------------
<S>                          <C>                 <C>                  <C>              <C>
Equity securities              61%                 54%                  68%              60%
Debt securities                31%                 30%                  26%              28%
Cash and equivalents            2%                  8%                   2%               7%
Venture capital                 6%                  8%                   4%               5%
---------------------------------------------------------------------------------------------
Total                         100%                100%                 100%             100%
---------------------------------------------------------------------------------------------
</TABLE>

The  long-term  rate of return on assets  (pre-tax)  is assumed to be 8.5% which
management  believes  is an  appropriate  long-term  expected  rate of return on
assets based on our investment strategy, asset allocation mix and the historical
performance  of equity  investments  over long periods of time.  The actual ten-
year compound rate of return for our Plans is greater than 8.5%.

Our  master  trust  investment  allocation  policy  target for the assets of the
pension  and other  postretirement  benefit  plans is 70%  equity  and 30% fixed
income.

During 2003,  KeySpan  conducted an asset and liability study  projecting  asset
returns and  expected  benefit  payments  over a ten-year  period.  Based on the
results of the study,  KeySpan has developed a multi-year  funding  strategy for
its plans.  We believe  that it is  reasonable  to assume  assets can achieve or
outperform the assumed  long-term rate of return with the target allocation as a
result of  historical  out-performance  of  equity  investments  over  long-term
periods.


                                      122
<PAGE>


Cash Contributions: In 2004, KeySpan is expected to contribute approximately $89
million  to its  pension  plans  and  approximately  $58  million  to its  other
postretirement benefit plans.

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.  The
matching  contributions  are in  KeySpan's  common  stock.  For the years  ended
December 31, 2003, 2002 and 2001, we recorded an expense of $11.2 million, $11.2
million, and $11.0 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,  2003,  we had 13.1 million
shares,  or  approximately  $378.5  million of treasury  stock  outstanding.  We
completed this repurchase plan in 1999 and have since utilized treasury stock to
satisfy our common  stock  benefit  plans.  During  2003,  we issued 3.3 million
shares out of treasury  for the  dividend  reinvestment  feature of our Investor
Program,  the Employee Stock  Discount  Purchase Plan, the 401(k) Plan and Stock
Option Plans.

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

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.

At December 31, 2003 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 85,676 shares  outstanding  of 6% Preferred  Stock
Series A par value $100, in the aggregate totaling $83.6 million.


                                      123
<PAGE>


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

Note 6. Long-Term Debt

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, 2003, each of which is guaranteed by KeySpan.

Further,  KeySpan had $2.36 billion of medium and long term notes outstanding at
December 31, 2003 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 notes of $710 million have
interest rates ranging from 6.15% to 9.75% and mature in 2005-2025.

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

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

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

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

                                      124


<PAGE>


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,
2003, 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 0.60% to 1.20% during the year ended December 31, 2003, at which
time the rate was 1.10%.

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
2003 we called  approximately  $447 million  aggregate  principal amount of such
promissory  notes at the  applicable  redemption  prices plus accrued and unpaid
interest  through the dates of  redemption.  Therefore,  at December  31,  2003,
$155.4  million of these  promissory  notes  remained  outstanding.  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. At December
31, 2003, KeySpan was in compliance with this requirement.

Interest savings  associated with this redemption were $15.6 million  after-tax,
or $0.10 per share,  in 2003. We applied the provisions of SFAS 145  "Rescission
of FASB  Statement  No. 4, 44 and 64,  Amendment of FASB  Statement  No. 13, and
Technical  Corrections"  and  recorded an expense of $18.2  million,  reflecting
redemption costs, as well as the write-off of previously  deferred debt issuance
costs.  This expense has been recorded in other income and  (deductions)  in the
Consolidated Statement of Income.

MEDS Equity Units: At December 31, 2003, KeySpan had $460 million of MEDS Equity
Units outstanding 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,  May 2005,  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.

There  were  eight  million  MEDS  Equity  units  issued  which are  subject  to
conversion  upon  execution of the three-year  forward  purchase  contract.  The
number of shares to be issued depends on the average closing price of our common
stock over the 20 day trading  period  ending on the third  trading day prior to
May 16, 2005. If the average  closing price over this time frame is less than or
equal to $35.30 of KeySpan's  common stock,  11.3 million shares will be issued.
If the average  closing  price over this time frame is greater  than or equal to
$42.36,  9.4  million  shares will be issued.  The number of shares  issued at a
price  between  $35.30 and $42.36 will be between  9.4 million and 11.3  million
based upon a sliding scale.


                                      125
<PAGE>


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.

Industrial  Development  Revenue Bonds:  In the fourth quarter of 2003,  KeySpan
closed on a  financing  transaction  pursuant to which $128  million  tax-exempt
bonds  with a 5.25%  coupon  maturing  in June 2027 were  issued on its  behalf.
Fifty-three  million dollars of these Industrial  Development Revenue Bonds were
issued  through  the Nassau  County  Industrial  Development  Authority  for the
construction of the Glenwood  electric-generation  peaking plant and the balance
of $75 million was issued by the Suffolk County Industrial Development Authority
for the Port  Jefferson  electric-generation  peaking  plant.  Proceeds from the
transaction   were  used  to  repay   commercial   paper  used  to  finance  the
construction,  installation  and  equipping of the two  facilities.  KeySpan has
guaranteed  all payment  obligations  of our  subsidiaries  with regard to these
bonds.

First Mortgage  Bonds:  Colonial Gas Company,  Essex Gas Company,  ENI and their
respective  subsidiaries,  have  issued  and  outstanding  approximately  $153.2
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.

Authority Financing Notes:  Certain of our electric generation  subsidiaries can
issue   tax-exempt  bonds  through  the  New  York  State  Energy  Research  and
Development  Authority.  At  December  31,  2003,  $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 2003 ranged from 0.56% to 1.15%,
through December 31, 2003, at which time the rate was 1.10%.

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 0.70 % to 1.21% from  January 1, 2003  through
December 31, 2003 at which time the rate was 1.08%.


                                      126
<PAGE>


Ravenswood  Master  Lease:  We  have an  arrangement  with a  variable  interest
unaffiliated 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  financing entity
that acquired a portion of the facility,  three steam generating units, directly
from  Consolidated  Edison and leased it to a KeySpan  subsidiary.  The variable
interest financing entity acquired the property for $425 million,  financed with
debt of $412.3 million (97% of  capitalization)  and equity of $12.7 million (3%
of  capitalization).  Monthly  lease  payments  are  substantially  equal to the
monthly interest expense on the debt securities.

In December 2003,  KeySpan  implemented FASB  Interpretation  No. 46 ("FIN 46"),
"Consolidation of Variable Interest Entities,  an Interpretation of ARB No. 51."
This  Interpretation  required  us to,  among  other  things,  consolidate  this
variable  interest  entity  and  classify  the  Master  Lease as $412.3  million
long-term debt on the Consolidated Balance Sheet.  Further, we recorded an asset
on the Consolidated  Balance Sheet for an amount substantially equal to the fair
market  value  of  the  leased  assets  at the  inception  of  the  lease,  less
depreciation  since that date. Under the terms of our credit facility the Master
Lease  has been  considered  debt in the ratio of  debt-to-total  capitalization
since the inception of the lease and therefore,  implementation of FIN 46 has no
impact on our credit facility. (See Note 7 "Contractual  Obligations,  Financial
Guarantees and Contingencies" for additional  information  regarding the leasing
arrangement associated with the Master Lease Agreement and FIN 46 implementation
issues.)

PUHCA   Authorization:   In  the  fourth   quarter  of  2003  KeySpan   received
authorization from the SEC, under PUCHA, to issue up to an additional $3 billion
of securities  through  December 31, 2006. This  authorization  provides KeySpan
with the necessary  flexibility to finance future capital  requirements over the
next three years.

Commercial Paper and Revolving Credit Agreements:  In June 2003, KeySpan renewed
its $1.3 billion  revolving credit facility,  which was syndicated among sixteen
banks. The credit facility  supports  KeySpan's  commercial  paper program,  and
consists  of two  separate  credit  facilities  with  different  maturities  but
substantially similar terms and conditions: a $450 million facility that extends
for 364 days, and a $850 million facility that is committed for three years. The
fees for the facilities are subject to a ratings-based  grid, with an annual fee
that ranges from eight to twenty five basis  points on the 364-day  facility and
ten to thirty basis points on the three-year  facility.  Both credit  agreements
allow  for  KeySpan  to  borrow  using   several   different   types  of  loans;
specifically,   Eurodollar   loans,  ABR  loans,  or  competitively  bid  loans.
Eurodollar  loans are based on the Eurodollar rate plus a margin.  ABR loans are
based on the highest of the Prime Rate, the base CD rate plus 1%, or the Federal
Funds Effective Rate plus 0.5%,  plus a margin.  Competitive bid loans are based
on bid  results  requested  by KeySpan  from the  lenders.  The  margins on both


                                      127
<PAGE>

facilities  are  ratings  based and range from zero basis  points to 112.5 basis
points.  The margins are increased if outstanding  loans are in excess of 33% of
the total facility.  In addition,  the 364-day  facility has a one-year term out
option,  which would cost an additional 0.25% if utilized.  We do not anticipate
borrowing against this facility; however, if the credit rating on our commercial
paper program were to be downgraded, it may be necessary to do so.

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

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.  At December 31, 2003,  consolidated  indebtedness,  as calculated
under   the  terms  of  the   credit   facility,   was  58.2%  of   consolidated
capitalization.  Violation of this covenant  could result in the  termination of
the credit facility and the required  repayment of amounts borrowed  thereunder,
as well as possible cross defaults under other debt agreements.

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, 2003, KeySpan was in compliance with
all covenants.

At December 31,  2003,  we had cash and  temporary  cash  investments  of $205.8
million.  During 2003,  we repaid  $433.8  million of  commercial  paper and, at
December 31, 2003,  $481.9  million of  commercial  paper was  outstanding  at a
weighted average annualized  interest rate of 1.2%. We had the ability to borrow
up to an additional  $818.1  million at December 31, 2003,  under the commercial
paper program.

Houston  Exploration has a revolving  credit facility with a commercial  banking
syndicate that provides  Houston  Exploration with a commitment of $300 million,
which can be  increased,  at its option to a maximum of $350  million with prior
approval from the banking syndicate. The credit facility is subject to borrowing
base   limitations,   currently  set  at  $300  million  and  is   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,  with the  exception  of trade  payables,  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.


                                      128
<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, 2003, Houston Exploration was in compliance with all financial covenants.

During 2003, Houston Exploration borrowed $239 million under its credit facility
and repaid $264  million.  At December  31,  2003,  $127  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,  2003,  $172.6  million of borrowing  capacity was
available.

In 2003,  KeySpan Canada replaced its two outstanding credit facilities with one
new facility with three tranches that combined  allowed KeySpan Canada to borrow
up to  approximately  $125  million.  At the time of the partial sale of KeySpan
Canada,  net proceeds from the sale of $119.4  million plus an additional  $45.7
million  drawn under the new credit  facilities  were used to pay down  existing
outstanding  debt of $160.4 million.  During the third quarter of 2003,  KeySpan
Canada issued Cdn$125  million,  or  approximately  US$93 million,  in long-term
secured notes in a private placement,  as previously mentioned.  The proceeds of
the offering  were used to pay-down,  in its  entirety,  outstanding  borrowings
under the  credit  facility.  Further,  one tranch of the  credit  facility  was
discontinued.  At December 31, 2003,  KeySpan  Canada's  credit facility has the
following two tranches with the following maturities:  (i) $37.5 million matures
in 364 days: and (ii) $37.5 million matures in two years.  During 2003,  KeySpan
Canada borrowed $71.5 million from its prior credit facilities and repaid $240.3
million.  During  the fourth  quarter of 2003,  KeySpan  Canada  borrowed  $18.1
million  under the new  facility  and at  December  31,  2003  $56.9  million is
available  for future  borrowing.  KeySpan is not a guarantor of this  facility.

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 6.12%.

Debt Maturity:  The following table reflects the maturity  schedule for our debt
repayment requirements,  including capitalized leases and related maturities, at
December 31, 2003:


--------------------------------------------------------------------------------
                                     Long-Term        Capital
 (In Thousands of Dollars)              Debt          Leases           Total
--------------------------------------------------------------------------------
 Repayments:
     Year 1                              $ 333       $ 1,138            $ 1,471
     Year 2                          1,302,333         1,096          1,303,429
     Year 3                            512,333         1,003            513,336
     Year 4                                333         1,063              1,396
     Year 5                            160,761         1,129            161,890
     Thereafter                      3,649,613         7,552          3,657,165
--------------------------------------------------------------------------------
                                    $5,625,706      $ 12,981        $ 5,638,687
--------------------------------------------------------------------------------


                                      129
<PAGE>


Note 7. Contractual Obligations, Financial Guarantees and Contingencies

Lease Obligations:  Lease costs included in operation expense were $82.1 million
in 2003  reflecting,  primarily,  the Master Lease and the lease of our Brooklyn
headquarters of $29.3 million and $14.6 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, 2002 and 2001
were $71.1 million and $75.8 million, respectively. As previously mentioned, the
Master  Lease has been  consolidated  as  required  by FIN 46,  and as a result,
future lease payments will be reflected as interest  expense on the Consolidated
Statement of Income  beginning  January 1, 2004.  The future  minimum cash lease
payments  under various  leases,  excluding  the Master Lease,  all of which are
operating leases, are $58.9 million per year over the next five years and $122.2
million, in the aggregate,  for all years thereafter.  (See discussion below for
further information regarding the Master Lease.)

Variable  Interest  Entity:  As  mentioned,  KeySpan has an  arrangement  with a
variable  interest  entity  through  which we lease a portion of the  Ravenswood
facility.  We  acquired  the  Ravenswood  facility,  a  2,200-megawatt  electric
generating  facility located in Queens,  New York, 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.  Monthly lease payments
substantially equal the monthly interest expense on such debt securities.

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.
At this  time,  KeySpan  intends  to  maintain  a  leasing  arrangement  for the
foreseeable  future.  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.


                                      130
<PAGE>


In December 2003,  KeySpan  implemented FASB  Interpretation  No. 46 ("FIN 46"),
"Consolidation of Variable Interest Entities,  an Interpretation of ARB No. 51."
This  Interpretation  required  us to,  among  other  things,  consolidate  this
variable  interest  entity  and  classify  the  Master  Lease as $412.3  million
long-term debt on the Consolidated  Balance Sheet based on our current status as
primary  beneficiary.  Further, we recorded an asset on the Consolidated Balance
Sheet for an amount  substantially  equal to the fair market value of the leased
assets at the  inception of the lease,  less  depreciation  since that date,  or
approximately  $388  million.  As previously  mentioned,  under the terms of our
credit  facility  the  Master  Lease  has been  considered  debt in the ratio of
debt-to-total  capitalization  since the  inception of the lease and  therefore,
implementation of FIN 46 has no impact on our credit facility.  In addition,  we
recorded  a $37.6  million  after-tax  charge,  or $0.23  per  share,  change in
accounting  principle  on the  Consolidated  Statement  of Income,  representing
approximately four and a half years of depreciation. Based upon expected average
outstanding  shares,  we anticipate  the  incremental  impact of the  additional
depreciation  expense for 2004 to be approximately $0.05 per share. Yearly lease
payments will be reflected as interest expense on the Consolidated  Statement of
Income  beginning  January 1, 2004.  Future minimum lease payments are $30.8 per
year over the next five years and $15.4 million for 2009.

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.

Asset  Retirement  Obligations:  On January 1, 2003,  KeySpan  adopted 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.
At  December  31,  2003,  the  present  value  of our  future  asset  retirement
obligation  ("ARO") was  approximately  $92.4 million,  primarily related to our
investment in Houston  Exploration.  The  cumulative  effect of SFAS 143 and the
change in  accounting  principle  was a benefit to net  income of $0.2  million,
after-tax.


                                      131
<PAGE>


The  following  table  describes  on a  pro-forma  basis  the  asset  retirement
obligation  associated with Houston  Exploration as if SFAS 143 had been adopted
on January 1, 2002.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                               For the Year Ended December 31,
 (In Thousands of Dollars)                                     2003                      2002
-----------------------------------------------------------------------------------------------
<S>                                                          <C>                       <C>
 ARO Liability at January 1,                                $ 57,197                  $ 45,759
 Additions from drilling                                       5,738                     8,507
 Additions from purchases                                     29,244                       286
 Deletions from abandonment                                     (160)                        -
 Changes resulting from timing                                (3,330)                        -
 ARO accretion expense                                         3,668                     2,645
-----------------------------------------------------------------------------------------------
 ARO Liability at December 31,                              $ 92,357                  $ 57,197
-----------------------------------------------------------------------------------------------
 Reflected on Consolidated Balance Sheet
 ARO Liability - Current                                    $  7,703                       N/A
 ARO Liability - Long term                                  $ 84,654                       N/A
-----------------------------------------------------------------------------------------------
</TABLE>

KeySpan's largest asset base is its gas transmission and distribution  system. A
legal obligation exists due to certain safety requirements at final abandonment.
In  addition,  a legal  obligation  may be  construed  to exist with  respect to
KeySpan's   liquefied  natural  gas  ("LNG")  storage  tanks  due  to  clean  up
responsibilities  upon cessation of use.  However,  mass assets such as storage,
transmission and distribution  assets are believed to operate in perpetuity and,
therefore,  have  indeterminate  cash flow estimates.  Since that exposure is in
perpetuity  and cannot be measured,  no liability  will be recorded  pursuant to
SFAS 143.  KeySpan's ARO will be re-evaluated in future periods until sufficient
information exists to determine a reasonable estimate of fair value.

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, 2003, the following  amounts would have to be
paid by KeySpan in the event of non-payment  by the primary  obligor at the time
payment is due:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
                                                           Amount of
(In Thousands of Dollars)                                   Exposure     Expiration Dates
------------------------------------------------------------------------------------------
<S>                                         <C>            <C>            <C>
Medium-Term Notes - KEDLI                   (i)           $   525,000      2008-2010
Industrial Development Revenue Bonds        (ii)              128,000         2027
Master Lease  - Ravenswood                  (iii)             425,000         2004
Surety Bonds                                (iv)              168,000      Revolving
Commodity Guarantees and Other              (v)                43,000         2005
Letters of Credit                           (vi)               67,000         2004
------------------------------------------------------------------------------------------
                                                          $ 1,356,000
------------------------------------------------------------------------------------------
</TABLE>


                                      132
<PAGE>


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

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

(ii) KeySpan has fully and unconditionally guaranteed the payment obligations of
     its  subsidiaries  with regard to $128  million of  Industrial  Development
     Revenue  Bonds  issued   through  the  Nassau  County  and  Suffolk  County
     Industrial Development Authorities for the construction of the Glenwood and
     Port Jefferson  electric-generation peaking plants. The face value of these
     notes are included in long-term debt on the Consolidated Balance Sheet.

(iii)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.

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

(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, 2003.

(vi) KeySpan has issued stand-by  letters of credit in the amount of $67 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  or  letters  of credit  and we have no reason  to  believe  that our
subsidiaries  will  default on their  current  obligations.  However,  we cannot
predict when or if any  defaults may take place or the impact such  defaults may
have on our  consolidated  results of  operations,  financial  condition or cash
flows.


                                      133
<PAGE>


In June 2003,  Hawkeye Electric,  LLC et al.  ("Hawkeye") and KeySpan reached an
agreement settling certain legal matters. Under the terms of the settlement: (i)
certain obligations  between the parties have been modified and clarified,  (ii)
certain  contracts  were awarded to Hawkeye,  (iii)  certain  credit and bonding
support made available by KeySpan to Hawkeye was terminated and (iv) KeySpan and
a Hawkeye  affiliate closed on a $55 million  long-term note receivable due from
Hawkeye on July 20, 2018 bearing interest at an annual rate of 5% and secured by
a power plant in Greenport, New York.

Fixed Charges Under Firm Contracts:  Our utility subsidiaries and the Ravenswood
facility  have entered  into various  contracts  for gas  delivery,  storage and
supply  services.  Certain of these  contracts  require payment of annual demand
charges in the aggregate amount of approximately $452 million. We are liable for
these payments regardless of the level of service we require from third parties.
Such charges associated with gas distribution operations are currently recovered
from utility customers through the gas adjustment clause.

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.

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

KeySpan  and  certain of its  current  and former  officers  and  directors  are
defendants  in a  consolidated  class action  lawsuit filed in the United States
District Court for the Eastern District of New York. This lawsuit alleges, 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.  In October
2001, a shareholder's  derivative action was commenced in the same court against
certain  current and former 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. On June 12,
2002,  a  second   derivative   action  was  commenced  which  asserted  similar


                                      134
<PAGE>


allegations.  Each of these proceedings seeks monetary damages in an unspecified
amount.  On March 18,  2003,  the court  granted our motion to dismiss the class
action  complaint.  The court's order dismissed  certain class  allegations with
prejudice,  but provided the  plaintiffs a final  opportunity to file an amended
complaint concerning the remaining allegations.  In April 2003, plaintiffs filed
an amended complaint and in July 2003 the court denied our motion to dismiss the
amended complaint but did strike certain allegations.  On November 20, 2003, the
court  granted  our  motion for  reconsideration  of the July 2003 order and the
court struck additional allegations from the amended complaint which effectively
limited the potential class period. On December 19, 2003, KeySpan filed a motion
to dismiss the derivative actions. The motion is still pending.  KeySpan intends
to  vigorously  defend  each of these  proceedings.  However,  we are  unable to
predict the outcome of these  proceedings  or what effect,  if any, such outcome
will have on our financial condition, results of operations or cash flows.

KeySpan  subsidiaries,  along with  several  other  parties,  have been named as
defendants in numerous  proceedings filed by plaintiffs claiming various degrees
of injury from asbestos  exposure at  generating  facilities  formerly  owned by
LILCO and others.  In connection with the May 1998  transaction with LIPA, costs
incurred by KeySpan for  liabilities  for  asbestos  exposure  arising  from the
activities  of  the  generating   facilities   previously  owned  by  LILCO  are
recoverable  from LIPA  through  the Power  Supply  Agreement  between  LIPA and
KeySpan.

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

As previously reported,  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  commenced  this
proceeding  because it believed  that,  among other  things,  the former  owners
misstated  the  financial  statements  of the  Roy  Kay  companies  and  certain
underlying  work-in-progress  schedules.  The former owners filed  counterclaims
against  KeySpan  and certain of its  subsidiaries,  as well as certain of their
respective  officers,  to recover  damages  they  claimed 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.  In March 2004,  KeySpan  entered into an agreement  with
these formers owners settling this proceeding, the terms of which did not have a
material effect on our financial condition or results of operations.


                                      135
<PAGE>


Other  Contingencies:  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,  the terms and  conditions  thereof.  In
addition, given the complexity of these agreements,  disputes arise from time to
time between  KeySpan and LIPA  concerning  the rights and  obligations  of each
party to make and receive  payments  as required  pursuant to the terms of these
agreements. As a result, KeySpan is unable to determine what effect, if any, the
ultimate  resolution of these  disputes will have on its financial  condition or
results of operations.

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.

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.

Land, Manufactured Gas Plants and Related Facilities

New York Sites:  Within the State of New York we have  identified  43 historical
manufactured gas plant ("MGP") sites and related facilities, which were 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 the
NYPSC and the DEC for inclusion on appropriate site inventories.  Administrative
Orders on Consent  ("ACO") or  Voluntary  Cleanup  Agreements  ("VCA") have been
executed with the DEC to address the  investigation  and remediation  activities
associated with certain sites. Investigation and remediation activities required
at the  remaining  sites will be  addressed  as part of an  application  KeySpan
submitted to the DEC in October 2003 under its Voluntary  Cleanup  Program ("VCA
Application").

We have  identified 28 of these sites as being  associated  with the  historical
operations of KEDNY.  One site has been fully  remediated.  The remaining  sites
will  be  investigated  and,  if  necessary,  remediated  under  the  terms  and
conditions of ACOs or VCAs.  Expenditures incurred to date by us with respect to
KEDNY  MGP-related  activities total $38.8 million.  In July 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.


                                      136
<PAGE>


The  remaining  15 sites  have  been  identified  as being  associated  with the
historical operations of KEDLI. Expenditures incurred to date by us with respect
to KEDLI  MGP-related  activities  total $32.2 million.  One site has been fully
investigated  and  requires  no  further  action.  The  remaining  sites will be
investigated and, if necessary, remediated under the conditions of ACOs or VCAs.
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  cost of our KEDNY and KEDLI  MGP-related
environmental  remediation  activities will be $226.4 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 $71 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.  At December 31,  2003,  we have  reflected a regulatory  asset of $245.3
million for our KEDNY/KEDLI MGP sites. In accordance with NYPSC policy,  KeySpan
records  a  reduction  to  regulatory  liabilities  as costs  are  incurred  for
environmental  clean-up  activities.  At December  31,  2003,  these  previously
deferred  regulatory  liabilities  totaled $61.0 million. In October 2003, KEDNY
and KEDLI filed a joint  petition  with the NYPSC  seeking  rate  treatment  for
additional environmental costs that may be incurred in the future.

We are  also  responsible  for  environmental  obligations  associated  with the
Ravenswood  facility,  purchased  from  Consolidated  Edison in 1999,  including
remediation  activities  associated with its historical  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 $3.4  million,  which amount has been
accrued by us. Expenditures incurred to date total $1.6 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 of
these sites. A subsidiary of National Grid USA ("National  Grid"),  formerly New
England Electric System, has assumed  responsibility for remediating 11 of these


                                      137
<PAGE>

sites,  subject  to a limited  contribution  from  Boston Gas  Company,  and has
provided  full  indemnification  to Boston Gas Company  with  respect to 8 other
sites.  In  addition,  Boston Gas Company,  Colonial Gas Company,  and Essex Gas
Company has each assumed  responsibility  for remediating 3 sites. At this time,
it is uncertain as to whether Boston Gas Company,  Colonial Gas Company or Essex
Gas Company have or share responsibility for remediating any of the 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.  In October 2002, Boston Gas Company filed a complaint in
the United States  District Court -  Massachusetts  District  against one of the
insurance  companies that issued  comprehensive  general  liability  policies to
Boston Gas Company for its  remaining  sites.  The outcome of these  proceedings
cannot be determined at this time.

We  presently  estimate  the  remaining  cost  of  these   Massachusetts   KEDNE
MGP-related environmental cleanup activities will be $25.4 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 $13.5 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.  At four of these sites we have entered
into cost sharing  agreements  with other parties who share  responsibility  for
remediation of these sites.  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.

We  presently   estimate  the   remaining   cost  of   EnergyNorth   MGP-related
environmental  cleanup  activities will be $13.9 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 $7.8 million.


                                      138
<PAGE>


By rate  orders,  the  DTE  and the  NHPUC  provide  for  the  recovery  of site
investigation and remediation costs and,  accordingly,  at December 31, 2003, we
have reflected a regulatory  asset of $51.5 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  KeySpan  New  England,  LLC,  a  successor  company to Eastern
Enterprises, for which we may have or share environmental remediation or ongoing
maintenance   responsibility.   These  three  sites,  located  in  Philadelphia,
Pennsylvania, New Haven, Connecticut and Everett, Massachusetts, were associated
with  historical  operations  involving  the  production  of  coke  and  related
industrial processes. Honeywell International,  Inc. and Beazer East, Inc. (both
former  owners and/or  operators of certain  facilities at Everett ("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 a portion of that 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 for, among other things,  reallocation of proportionate  liability. In
2002,  Beazer  East  commenced  an  action  in 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.

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  $25.6 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 $7.2 million.

We believe that in the aggregate,  the accrued liability for these MGP sites and
related  facilities  identified  above are reasonable  estimates of the probable
cost for the  investigation  and remediation of these sites and  facilities.  As
circumstances  warrant,  we  periodically  re-evaluate  the accrued  liabilities
associated with MGP sites and related facilities. We did such a re-evaluation in
2003 and the results of this study have been  reflected in  KeySpan's  accruals.
The  re-evaluation  of KeySpan's  accruals  resulted in a $10 million benefit to
earnings in 2003. We may be required to investigate and, if necessary, remediate
each site previously  noted, 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.


                                      139
<PAGE>


Note 8.  Hedging, Derivative Financial Instruments and Fair Values

Financially-Settled  Commodity Derivative Instruments - Hedging Activities: From
time  to  time,  KeySpan   subsidiaries  have  utilized   derivative   financial
instruments,  such as futures, options and swaps, for the purpose of hedging the
cash flow variability  associated with changes in commodity  prices.  KeySpan is
exposed to commodity price risk primarily with regard to its gas exploration and
production  activities  and  its  electric  generating  facilities.   Derivative
financial  instruments  are employed by Houston  Exploration  to hedge cash flow
variability  associated  with  forecasted  sales of natural gas. The  Ravenswood
facility  uses  derivative   financial   instruments  to  hedge  the  cash  flow
variability  associated  with the  purchase  of natural gas and oil that will be
consumed  during the generation of  electricity.  The  Ravenswood  facility also
hedges  the cash  flow  variability  associated  with a portion  of peak  season
electric  energy  sales.  In  addition,  during  2003  KeySpan  Canada  employed
derivative financial instruments to hedge cash flow variability  associated with
the  purchase of natural gas and  electricity  used in the  operation of its gas
processing plants; all such derivative instruments settled during the year.

The majority of these derivative financial instruments are cash flow hedges that
qualify  for  hedge   accounting  under  SFAS  133  "Accounting  for  Derivative
Instruments  and  Hedging  Activities",  as  amended by SFAS 149  "Amendment  of
Statement 133 on Derivative  Instruments and Hedging  Activities",  collectively
SFAS 133, and are not considered held for trading purposes as defined by current
accounting  literature.  Accordingly,  we  carry  the fair  market  value of our
derivative  instruments on the Consolidated Balance Sheet as either a current or
deferred asset or liability, as appropriate,  and defer the effective portion of
unrealized gains or losses in accumulated other comprehensive  income. Gains and
losses are  reclassified  from  accumulated  other  comprehensive  income to the
Consolidated  Statement of Income in the period the hedged  transaction  effects
earnings.  Gains and losses are  reflected as a component  of either  revenue or
fuel  and  purchased   power   depending  on  the  hedged   transaction.   Hedge
ineffectiveness  is  measured  using the change in  variable  cash flows and the
hypothetical derivative methods and recorded directly to earnings.

Houston  Exploration has utilized collars and purchased put options,  as well as
over-the-counter  ("OTC") swaps, to hedge the cash flow  variability  associated
with  forecasted  sales of a portion of its  natural  gas  production.  In 2003,
Houston  Exploration  hedged  slightly less than 70% of its gas  production.  At
December  31,  2003,  Houston  Exploration  has  hedge  positions  in place  for
approximately 70% of its estimated 2004 gas production,  with an effective floor
price  of $4.26  and an  effective  ceiling  price of  $5.65.  Further,  Houston
Exploration has hedge positions in place for  approximately 44% of its estimated
2005 gas  production,  with an  effective  floor price of $4.59 and an effective
ceiling price of $5.26.  Houston  Exploration  uses standard New York Mercantile
Exchange ("NYMEX") futures prices to value its swap positions, and, in addition,
uses  published  volatility in its  Black-Scholes  calculation  for  outstanding
options.  The maximum length of time over which Houston  Exploration  has hedged
such cash flow  variability  is through  December 2005. The fair market value of
these  derivative  instruments  at December  31,  2003 was a liability  of $36.9
million.  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 $32.1
million, or $20.9 million after-tax.


                                      140
<PAGE>


With respect to price exposure associated with fuel purchases for the Ravenswood
facility,  KeySpan  employs  standard  NYMEX  natural gas futures  contracts and
over-the-counter  financially  settled natural gas basis swaps to hedge the cash
flow  variability for a portion of forecasted  purchases of natural gas. KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow variability for a portion of forecasted  purchases of fuel oil that will be
consumed at the  Ravenswood  facility.  The maximum length of time over which we
have  hedged cash flow  variability  associated  with  forecasted  purchases  of
natural  gas and fuel oil is  through  September  2005.  We use  standard  NYMEX
futures  prices to value the gas futures  contracts  and market  quoted  forward
prices to value oil swap and natural gas basis swap  contracts.  The fair market
value of these derivative  instruments at December 31, 2003 was an asset of $0.4
million. These derivative instruments are reported in other comprehensive income
and are expected to be reclassified into earnings over the next twelve months.

We have also engaged in the use of  cash-settled  swap  instruments to hedge the
cash flow  variability  associated  with a portion  of  forecasted  peak  season
electric energy sales from the Ravenswood  facility.  The maximum length of time
over which we have hedged cash flow variability is through December 2004. We use
market quoted forward prices to value these  outstanding  derivatives.  The fair
market value of these  derivative  instruments at December 31, 2003 was an asset
of  $0.3  million.   These   derivative   instruments   are  reported  in  other
comprehensive  income and are expected to be reclassified into earnings over the
next twelve months.

The  table  below  summarizes  the fair  value of each  category  of  derivative
instrument  outstanding  at December  31, 2003 and its related  line item on the
Consolidated  Balance  Sheet.  Fair  value is the  amount  at  which  derivative
instruments could be exchanged in a current transaction between willing parties,
other than in a forced liquidation sale.

----------------------------------------------------------------------------
(In Thousands of Dollars)                              December 31, 2003
----------------------------------------------------------------------------
Gas Contracts:
  Other current assets                                     $          3,458
  Accounts payable and other liabilities                            (35,592)
  Other deferred liabilities                                         (4,734)

Oil Contracts:
  Other deferred charges                                                385

Electric Contracts:
  Other deferred charges                                                259
----------------------------------------------------------------------------
                                                           $        (36,224)
----------------------------------------------------------------------------


Financially-Settled  Commodity  Derivative  Instruments  that Do Not Qualify for
Hedge Accounting: KeySpan subsidiaries also employ a limited number of financial
derivatives that do not qualify for hedge  accounting  treatment under SFAS 133.
In  November  2003,  we sold a  "swaption"  to hedge the cash  flow  variability
associated  with 50 MW of forecasted  2004 summer electric energy sales from the


                                      141
<PAGE>

Ravenswood  facility.  The swaption is an option that gives the counterparty the
right, but not the obligation,  to enter into a swap transaction with KeySpan in
the future at a given strike price.  This swaption can be converted into a swap,
at the election of the  counterparty and has an expiration date of June 1, 2004.
The premium payment KeySpan received was recorded as a current  liability on the
Consolidated  Balance Sheet. The premium  generally will be recorded into income
at the time the swaption is either exercised or expires. An internally developed
option-pricing  model is used to value the swaption and at December 31, 2003 the
fair value of the swaption was immaterial.

At December 31,  2003,  KeySpan  Canada has a portfolio  of  financially-settled
natural  gas  collars  and swap  transactions  for  natural  gas  liquids.  Such
contracts  are executed by KeySpan  Canada to: (i) fix the price that is paid or
received by KeySpan Canada for certain physical  transactions  involving natural
gas  and  natural  gas  liquids  and  (ii)   transfer  the  price   exposure  to
counterparties.  These derivative financial  instruments also do not qualify for
hedge accounting  treatment.  At December 31, 2003, these  instruments had a net
fair market value of $1.0 million,  which was recorded as a $1.8 million current
asset and $0.8 million  current  liability on the  Consolidated  Balance  Sheet.
Based on the non-hedge designation of these instruments,  an unrealized gain was
recorded in the Consolidated Statement of Income.

Firm Gas Sales Derivative  Instruments - Regulated Utilities:  We use derivative
financial  instruments to reduce the cash flow  variability  associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution  operations.  Our strategy is to minimize  fluctuations in firm
gas sales prices to our regulated  firm gas sales  customers in our New York and
New England service territories. The accounting for these derivative instruments
is  subject  to  SFAS 71  "Accounting  for  the  Effects  of  Certain  Types  of
Regulation." Therefore, changes in the fair value of these derivatives have been
recorded as a  regulatory  asset or  regulatory  liability  on the  Consolidated
Balance  Sheet.  Gains  or  losses  on the  settlement  of these  contracts  are
initially  deferred and then  refunded to or  collected  from our firm gas sales
customers consistent with regulatory  requirements.  At December 31, 2003, these
derivatives  had a net fair market value of $9.9 million and are  reflected as a
regulatory liability on the Consolidated Balance Sheet.


                                      142
<PAGE>


Physically-Settled  Commodity  Derivative  Instruments:   SFAS  133  establishes
criteria that must be satisfied in order for option contracts, forward contracts
with  optionality  features,  or contracts that combine a forward contract and a
purchase  option  contract to be exempted as normal  purchases and sales.  Based
upon a continuing  review of our  physical gas  contracts,  we  determined  that
certain  contracts for the physical  purchase of natural gas associated with our
regulated gas utilities are not exempt as normal purchases from the requirements
of SFAS 133.  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.  At December  31, 2003 these  contracts  had a net
negative fair market value of $1.9 million,  and are reflected as a $6.9 million
regulatory  asset and $5.0  million  regulatory  liability  on the  Consolidated
Balance Sheet.

Interest Rate Derivative Instruments: In May 2003, we entered into interest rate
swap  agreements  in which we swapped  $250  million of 7.25% fixed rate debt to
floating rate debt. Under the terms of the agreements, we will receive the fixed
coupon  rate  associated  with  these  bonds and pay our swap  counterparties  a
variable  interest rate based on LIBOR,  that is reset on a  semi-annual  basis.
These swaps are  designated  as  fair-value  hedges and qualify for  "short-cut"
hedge  accounting  treatment  under SFAS 133.  During the  twelve  months  ended
December 31, 2003, we paid our  counterparty an average  interest rate of 6.43%,
and as a result, we realized  interest savings of $1.2 million.  The fair market
value of this derivative was negligible at December 31, 2003.

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

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

Weather  Derivatives:  The utility tariffs associated with KEDNE's operations do
not contain weather normalization  adjustments.  As a result,  fluctuations from
normal weather may have a significant positive or negative effect on the results
of these  operations.  To  mitigate  a  substantial  portion  of the  effect  of
fluctuations  from normal weather on our financial  position and cash flows,  we


                                      143

<PAGE>


sold  heating  degree-day  call  options and  purchased  heating-degree  day put
options for the November  2002-March  2003 winter  season.  With respect to sold
call  options,  KeySpan  was  required  to make a payment of $40,000 per heating
degree day to its  counterparties  when actual  weather  experienced  during the
November 2002 - March 2003 time frame was above 4,470 heating degree days, which
equates  to  approximately  1% colder  than  normal  weather.  With  respect  to
purchased put options,  KeySpan would have received a $20,000 per heating degree
day payment from its counterparties  when actual weather was below 4,150 heating
degree days, or approximately 7% warmer than normal.  Based on the terms of such
contracts,  we account for such instruments pursuant to the requirements of EITF
99-2,  "Accounting for Weather  Derivatives."  In this regard,  such instruments
were  accounted  for using the  "intrinsic  value  method"  as set forth in such
guidance.  During the first quarter of 2003,  weather was 10% colder than normal
and, as a result, $11.9 million was recorded as a reduction to revenues.

In October  2003,  we entered  into  heating-degree  day call and put options to
mitigate the effect of  fluctuations  from normal  weather on KEDNE's  financial
position and cash flows for the 2003/2004  winter heating season - November 2003
through March 2004. With respect to sold call options,  KeySpan will be required
to make a payment of $27,500 per heating degree day to its  counterparties  when
actual weather  experienced during this time frame is above 4,440 heating degree
days, which equates to approximately 2% colder than normal weather, based on the
most recent 20-year average for normal  weather.  The maximum amount KeySpan may
be required to pay on its sold call  options is $5.5  million.  With  respect to
purchased  put options,  KeySpan  will receive a $27,500 per heating  degree day
payment  from its  counterparties  when actual  weather is below  4,266  heating
degree days, or approximately 2% warmer than normal.  The maximum amount KeySpan
may receive on its  purchased  put options is $11 million.  The net premium cost
for these options was $0.4 million. We account for these derivatives pursuant to
the requirements of EITF 99-2.  During the fourth quarter of 2003,  weather,  as
measured in heating degree-days,  was slightly warmer normal and, as a result, a
$0.5 million benefit was recorded through 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
non-performance by a counterparty to a derivative  contract,  the desired impact
may not be  achieved.  The risk of  counterparty  non-performance  is  generally
considered a credit risk and is actively managed by assessing each  counterparty
credit  profile and  negotiating  appropriate  levels of  collateral  and credit
support.  We  believe  that our  credit  risk  related  to the  above  mentioned
derivative financial instruments is no greater than the risk associated with the
primary  contracts which they hedge and that the elimination of a portion of the
price risk reduces  volatility in our reported results of operations,  financial
position and cash flows and lowers overall business risk.

Long-term Debt: The following  tables depict the fair values and carrying values
of KeySpan's long-term debt at December 31, 2003 and 2002.

Fair Values of Long-Term Debt

------------------------------------------------------------------------------
                                                   Year Ended December 31,
(In Thousands of Dollars)                         2003                  2002
------------------------------------------------------------------------------
First Mortgage Bonds                        $   178,438           $   180,666
Notes                                         3,893,158             3,441,619
Gas Facilities Revenue Bonds                    683,354               674,828
Authority Financing Notes                        66,005                66,005
Promissory Notes                                158,837               616,240
MEDS Equity Units                               495,880               525,918
Tax Exempt Bonds                                129,558                     -
------------------------------------------------------------------------------
                                            $ 5,605,230           $ 5,505,276
------------------------------------------------------------------------------


                                      144
<PAGE>


Carrying Values of Long-Term Debt
------------------------------------------------------------------------------
(In Thousands of Dollars)                         2003                 2002
------------------------------------------------------------------------------
First Mortgage Bonds                        $   153,186           $   163,625
Notes                                         3,456,425             2,985,000
Gas Facilities Revenue Bonds                    648,500               648,500
Authority Financing Notes                        66,005                66,005
Promissory Notes                                155,422               602,427
MEDS Equity Units                               460,000               460,000
Master Lease                                    412,300                     -
Tax Exempt Bonds                                128,275                     -
------------------------------------------------------------------------------
                                            $ 5,480,113           $ 4,925,557
------------------------------------------------------------------------------


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.

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:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------
(In Thousands of Dollars)                                        2002           2001
---------------------------------------------------------------------------------------
<S>                                                           <C>             <C>
Revenues                                                    $  116,149      $  266,792
Pre-tax income (loss)                                           (4,624)         18,489
Income tax (expense) benefit                                     1,268          (7,571)
---------------------------------------------------------------------------------------
Income (loss) from discontinued operations                      (3,356)         10,918
---------------------------------------------------------------------------------------
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)
---------------------------------------------------------------------------------------
</TABLE>


                                      145
<PAGE>


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.  During 2003  KeySpan
incurred $11.4 million in operating losses,  which reflected provisions made for
the  resolution of outstanding  claims and change orders,  as well as additional
costs  incurred  in  connection  with the  collection  of  outstanding  contract
balances.

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 and 2001 the Roy Kay  companies  recorded
operating losses of $10.8 million and $137.8 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.


                                      146
<PAGE>


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.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                                                                          Year Ended December 31, 2003
                                                                                       Other
(In Thousands of Dollars)                     Guarantor          KEDLI              Subsidiaries      Eliminations     Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                          <C>              <C>                    <C>                  <C>           <C>
Revenues                                    $     507        $ 1,046,931            $ 5,868,230       $     (507)      $ 6,915,161
                                       --------------------------------------------------------------------------------------------
Operating Expenses
  Purchased gas                                     -            574,009              1,921,093                -         2,495,102
  Fuel and purchased power                          -                  -                414,633                -           414,633
  Operations and maintenance                   11,340            137,223              1,857,233                -         2,005,796
  Intercompany expense                          5,282              3,570                 (3,570)          (5,282)                -
  Depreciation and amortization                   (53)            77,603                496,524                -           574,074
  Operating taxes                                   -             77,503                340,733                -           418,236
                                       --------------------------------------------------------------------------------------------
Total Operating Expenses                       16,569            869,908              5,026,646           (5,282)        5,907,841
                                       --------------------------------------------------------------------------------------------

Gain on sale of property                            -             13,974                  1,149                -            15,123
Income from equity investments                    108                  -                 19,106                -            19,214
                                       --------------------------------------------------------------------------------------------
Operating Income (Loss)                       (15,954)           190,997                861,839            4,775         1,041,657
                                       --------------------------------------------------------------------------------------------

Interest charges                             (209,505)           (62,992)              (299,399)         264,202          (307,694)
Other income and (deductions)                 621,151             (8,636)                54,429         (699,415)          (32,471)
                                       --------------------------------------------------------------------------------------------
Total Other Income and (Deductions)           411,646            (71,628)              (244,970)        (435,213)         (340,165)
                                       --------------------------------------------------------------------------------------------


Income Taxes (Benefit)                        (28,663)            40,796                265,178                -           277,311
                                       --------------------------------------------------------------------------------------------
Earnings from Continuing Operations         $ 424,355        $    78,573            $   351,691       $ (430,438)      $   424,181

Cumulative  Change in Accounting
Principle                                           -                  -                (37,451)               -           (37,451)
                                       --------------------------------------------------------------------------------------------
Net Income                                  $ 424,355        $    78,573            $   314,240       $ (430,438)      $   386,730
                                       ============================================================================================
</TABLE>


                                      147
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                  Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                             Year Ended December 31, 2002
                                                                                       Other
(In Thousands of Dollars)                        Guarantor        KEDLI              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                             -               -                395,860                 -           395,860
  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)         80,056                303,860                 -           381,767
                                           -----------------------------------------------------------------------------------------
Total Operating Expenses                          13,904         650,892              4,385,386            (2,772)        5,047,410
                                           -----------------------------------------------------------------------------------------

Gain on sale of property                               -             317                  4,413                 -             4,730
Income from equity investments                       104               -                 13,992                 -            14,096
                                           -----------------------------------------------------------------------------------------
Operating Income (Loss)                          (13,337)        160,026                793,084             2,309           942,082
                                           -----------------------------------------------------------------------------------------

Interest charges                                (200,920)        (62,520)              (295,209)          257,145          (301,504)
Other income and (deductions)                    565,262           7,835                 60,222          (633,068)              251
                                           -----------------------------------------------------------------------------------------
Total Other Income and (Deductions)              364,342         (54,685)              (234,987)         (375,923)         (301,253)
                                           -----------------------------------------------------------------------------------------


Income Taxes (Benefit)                           (26,683)         36,746                233,416                 -           243,479
                                           -----------------------------------------------------------------------------------------
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>



                                      148

<PAGE>


<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                  Statement of Income
-----------------------------------------------------------------------------------------------------------------------------------
                                                                         Year Ended December 31, 2001
                                                                                   Other
(In Thousands of Dollars)                     Guarantor        KEDLI            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
                                        -----------------------------------------------------------------------------------------

Income from equity investments                      -               -                 13,129                 -            13,129
                                        -----------------------------------------------------------------------------------------
Operating Income (Loss)                         19396         144,591                650,017              (226)          813,778
                                        -----------------------------------------------------------------------------------------

Interest charges                             (230,618)        (65,206)              (264,286)          206,640          (353,470)
Other income and (deductions)                 426,346           9,721                  5,326          (447,316)           (5,923)
                                        -----------------------------------------------------------------------------------------
Total Other Income and (Deductions)           195,728         (55,485)              (258,960)         (240,676)         (359,393)
                                        -----------------------------------------------------------------------------------------


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>


                                      149
<PAGE>


<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
-----------------------------------------------------------------------------------------------------------------------------------
                                                                          December 31, 2003
                                                                                  Other
(In Thousands of Dollars)                   Guarantor           KEDLI          Subsidiaries        Eliminations       Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
ASSETS
<S>                                       <C>               <C>                <C>                  <C>                <C>
Current Assets
   Cash and temporary cash investments   $    97,567       $     1,554        $    106,630        $          -        $    205,751
   Accounts receivable, net                    3,298           209,151           1,243,459                   -           1,455,908
   Other current assets                        3,250           130,994             590,996                   -             725,240
                                       --------------------------------------------------------------------------------------------
                                             104,115           341,699           1,941,085                   -           2,386,899
                                       --------------------------------------------------------------------------------------------

Equity Investments                         4,475,949             1,123             153,520          (4,382,027)            248,565
                                       --------------------------------------------------------------------------------------------
Property
   Gas                                             -         1,899,375           4,622,876                   -           6,522,251
   Other                                           -                 -           6,150,355                   -           6,150,355
   Accumulated depreciation and
    depletion                                      -          (312,204)         (3,466,099)                  -          (3,778,303)
                                       --------------------------------------------------------------------------------------------
                                                   -         1,587,171           7,307,132                   -           8,894,303
                                       --------------------------------------------------------------------------------------------

Intercompany Accounts Receivable           3,105,571                 -           1,191,394          (4,296,965)                  -

Deferred Charges                             374,076           237,870           2,485,071                   -           3,097,017

                                       --------------------------------------------------------------------------------------------
Total Assets                             $ 8,059,711       $ 2,167,863        $ 13,078,202        $ (8,678,992)       $ 14,626,784
                                       ============================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                      $   125,892       $   165,613        $    850,092        $          -        $  1,141,597
   Notes payable                             481,900                 -                   -                   -             481,900
   Other current liabilities                 129,168            16,125              80,026                   -             225,319
                                       --------------------------------------------------------------------------------------------
                                             736,960           181,738             930,118                   -           1,848,816
                                       --------------------------------------------------------------------------------------------
Intercompany Accounts Payable                      -           116,197           2,596,202          (2,712,399)                  -
                                       --------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                          (48,059)          256,882           1,064,828                   -           1,273,651
Other deferred credits and liabilities       532,062           179,919             925,839                   -           1,637,820
                                       --------------------------------------------------------------------------------------------
                                             484,003           436,801           1,990,667                   -           2,911,471
                                       --------------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                3,707,785           782,223           3,553,967          (4,382,027)          3,661,948
Preferred stock                               83,568                 -                   -                   -              83,568
Long-term debt                             3,047,395           650,904           3,497,699          (1,584,566)          5,611,432
                                       --------------------------------------------------------------------------------------------
Total Capitalization                       6,838,748         1,433,127           7,051,666          (5,966,593)          9,356,948
                                       --------------------------------------------------------------------------------------------
Minority Interest in Subsidiary
 Companies                                         -                 -             509,549                   -             509,549
                                       --------------------------------------------------------------------------------------------
Total Liabilities & Capitalization       $ 8,059,711       $ 2,167,863        $ 13,078,202        $ (8,678,992)       $ 14,626,784
                                       ============================================================================================

</TABLE>


                                      150
<PAGE>

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

Equity Investments                              3,797,964            1,469            201,675         (3,736,379)           264,729
                                          ------------------------------------------------------------------------------------------
Property
   Gas                                                  -        1,773,028          4,352,501                  -          6,125,529
   Other                                                -                -          4,807,724                  -          4,807,724
   Accumulated depreciation and
    depletion                                           -         (282,832)        (3,065,829)                 -         (3,348,661)
                                          ------------------------------------------------------------------------------------------
                                                        -        1,490,196          6,094,396                  -          7,584,592
                                          ------------------------------------------------------------------------------------------

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

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

                                          ------------------------------------------------------------------------------------------
Total Assets                                  $ 7,870,969      $ 1,978,507       $ 11,198,862       $ (8,068,288)      $ 12,980,050
                                          ==========================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                           $   132,966      $    68,772       $ 894,916          $          -       $  1,096,654
   Notes payable                                  915,697                -                  -                  -            915,697
   Other current liabilities                      107,605          104,975             30,302                  -            242,882
                                          ------------------------------------------------------------------------------------------
                                                1,156,268          173,747            925,218                  -          2,255,233
                                          ------------------------------------------------------------------------------------------
Intercompany Accounts Payable                           -          178,843          2,071,682         (2,250,525)                 -
                                          ------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                               (43,110)         139,715            780,408                  -            877,013
Other deferred credits and liabilities            481,964          138,209            744,688                  -          1,364,861
                                          ------------------------------------------------------------------------------------------
                                                  438,854          277,924          1,525,096                  -          2,241,874
                                          ------------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                     2,983,214          647,089          3,050,668         (3,736,379)         2,944,592
Preferred stock                                    83,849                -                  -                  -             83,849
Long-term debt                                  3,208,784          700,904          3,395,777         (2,081,384)         5,224,081
                                          ------------------------------------------------------------------------------------------
Total Capitalization                            6,275,847        1,347,993          6,446,445         (5,817,763)         8,252,522
                                          ------------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies               -                -            230,421                  -            230,421
                                          ------------------------------------------------------------------------------------------
Total Liabilities & Capitalization            $ 7,870,969      $ 1,978,507       $ 11,198,862       $ (8,068,288)      $ 12,980,050
                                          ==========================================================================================
</TABLE>


                                      151
<PAGE>


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
------------------------------------------------------------------------------------------------------------------------------------
                                                                                    Year Ended December 31, 2003
                                                          --------------------------------------------------------------------------
                                                                                                         Other
(In Thousands of Dollars)                                         Guarantor         KEDLI             Subsidiaries     Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
<S>                                                              <C>             <C>                   <C>               <C>
Net Cash (Used in) Provided by Operating Activities             $ (547,516)      $ 162,786            $ 1,569,373       $ 1,184,643
                                                          --------------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                  -        (130,275)              (881,441)       (1,011,716)
   Proceeds from the sale of property and
    subsidiary stock                                                     -          15,123                294,573           309,696
   Investments in subsidiaries                                           -               -               (211,370)         (211,370)
   Issuance of note receiveable                                    (55,000)              -                      -           (55,000)
                                                          --------------------------------------------------------------------------
Net Cash (Used in) Investing Activities                            (55,000)       (115,152)              (798,238)         (968,390)
                                                          --------------------------------------------------------------------------
Financing Activities
    Proceeds from equity issuance                                  473,573               -                                  473,573
    Treasury stock issued                                           96,687               -                      -            96,687
    Redemption of LIPA promissory notes                           (447,005)              -                                 (447,005)
    Issuance of debt, net of payments                              300,000               -                119,287           419,287
    Redemption of preferred stock                                                        -                (14,293)          (14,293)
    Payment of commercial paper                                   (433,797)              -                                 (433,797)
    Common and preferred stock dividends paid                     (280,560)              -                                 (280,560)
    Other                                                           28,933               -                (23,944)            4,989
    Net intercompany accounts                                      873,944         (52,552)              (821,392)                -
                                                                                                                                  -
                                                          --------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities                611,775         (52,552)              (740,342)         (181,119)
                                                          --------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents            $    9,259       $  (4,918)           $    30,793       $    35,134
Cash and Cash Equivalents at Beginning of Period                    88,308           6,472                 75,837           170,617
                                                          --------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                      $   97,567       $   1,554            $   106,630       $   205,751
                                                          ==========================================================================
</TABLE>


<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
---------------------------------------------------------------------------------------------------------------------------------
                                                                                 Year Ended December 31, 2002
                                                         ------------------------------------------------------------------------
                                                                                                       Other
(In Thousands of Dollars)                                       Guarantor        KEDLI             Subsidiaries     Consolidated
---------------------------------------------------------------------------------------------------------------------------------
Operating Activities
<S>                                                            <C>            <C>                     <C>             <C>
Net Cash (Used in) Provided by Operating Activities            $ (97,981)     $ 188,955              $ 640,518       $   731,492
                                                         ------------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                -       (146,450)              (914,572)       (1,061,022)
   Other                                                               -            903                151,358           152,261
                                                         ------------------------------------------------------------------------
Net Cash (Used in) Investing Activities                                -       (145,547)              (763,214)         (908,761)
                                                         ------------------------------------------------------------------------
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)
   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>


                                      152
<PAGE>


<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                      Year Ended December 31, 2001
                                                           ------------------------------------------------------------------------
                                                                                                       Other
(In Thousands of Dollars)                                         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>


Note 13.   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 14.  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.


                                      153
<PAGE>


Note 15. Subsequent Events (Unaudited)

KeySpan  is  currently   analyzing   proposals  from  interested   investors  to
participate in the equity portion of a leveraged lease financing of a new 250 MW
combined cycle electric  generating  facility located at the existing Ravenswood
electric  generating  facility site. KeySpan is seeking to arrange for the lease
to be  consummated  in late  April to  coincide  with the  commencement  of full
commercial operation of the new facility.  At the closing, the new facility will
be acquired by the lessor from our  subsidiary,  KeySpan  Ravenswood,  LLC,  and
simultaneously  leased back to it. All  obligations of our subsidiary  under the
lease will be  unconditionally  guaranteed by KeySpan.  We anticipate  that this
lease  transaction  will generate  cash  proceeds  equivalent to the fair market
value of the facility,  currently  anticipated to be approximately $360 million.
It is expected  that the cash  proceeds  from this  transaction  will be used to
redeem  outstanding  commercial paper. It is intended for this lease transaction
to  qualify  as an  operating  lease  under  SFAS  98  "Accounting  for  Leases:
Sale/Leaseback  Transactions  Involving Real Estate;  Sales-Type  Leases of Real
Estate;  Definition  of the  Lease  Term;  an  Initial  Direct  Costs of  Direct
Financing Leases, an amendment of FASB Statements No.13, 66, 91 and a rescission
of FASB Statement No. 26 and Technical  Bulletin No. 79-11." The lease will have
a term of  approximately  35 years and operating lease expense is anticipated to
be between $15 million to $17 million per year.  Lease  payments will  fluctuate
from year to year, but are substantially paid over the first 16 years.

On February  27, 2004  KeySpan and KeySpan  Facilities  Income Fund (the "Fund")
announced  that the Fund has entered into an  agreement  to sell 15.617  million
units of the Fund at a price of $12.60  per unit for  gross  total  proceeds  of
approximately  CDN$196.8  million.  The proceeds of the offering will be used to
acquire a 35.91%  interest in the business of KeySpan Energy Canada  Partnership
("KeySpan   Canada")  from  KeySpan.   KeySpan  will  receive  net  proceeds  of
approximately  CDN$186.3  million  (or  approximately  US$139  million),   after
commissions and expenses.  This offer is subject to regulatory  approvals and is
expected to close on or about April 1, 2004. After closing, the Fund's ownership
in KeySpan  Canada  will  increase  from 39.1% to 75%.  KeySpan's  ownership  of
KeySpan Canada will decrease to approximately 25%.


                                      154
<PAGE>


Note 16. 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, 2003. Shareholders
other than KeySpan had a minority interest of approximately 45% in Houston
Exploration at December 31, 2003, 34% in 2002 and 33% in 2001. Gas and oil
operations, and reserves, were located in the United States in all years.

<TABLE>
<CAPTION>
Capitalized Costs Relating to Gas and Oil Producing Activities
--------------------------------------------------------------------------------------------------------------------------
                                                                                     (In Thousands of Dollars)
--------------------------------------------------------------------------------------------------------------------------
At December 31,                                                             2003               2002                2001
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>                 <C>                 <C>
Unproved properties not being amortized                               $   142,905         $   110,623         $   195,478
Properties being amortized - productive and nonproductive               2,429,891           1,917,287           1,590,014
--------------------------------------------------------------------------------------------------------------------------
Total capitalized costs                                                 2,572,796           2,027,910           1,785,492
Accumulated depletion                                                  (1,159,509)           (968,713)           (791,194)
--------------------------------------------------------------------------------------------------------------------------
Net capitalized costs                                                 $ 1,413,287         $ 1,059,197         $   994,298
--------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
Costs Incurred in Property Acquisition, Exploration and Development Activities
-------------------------------------------------------------------------------------------------------------------------
                                                                                   (In Thousands of Dollars)
-------------------------------------------------------------------------------------------------------------------------
At December 31,                                                        2003                 2002                 2001
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>                  <C>                  <C>
Acquisition of properties -
     Unproved properties                                            $  61,484            $  14,600             $  31,718
     Proved properties                                                171,297               90,004                85,435
Exploration                                                            66,259               28,343                74,497
Development                                                           170,493              139,108               191,927
Asset retirement obligation                                            31,858                    -                     -
-------------------------------------------------------------------------------------------------------------------------
Total costs incurred                                                $ 501,391            $ 272,055             $ 383,577
-------------------------------------------------------------------------------------------------------------------------
</TABLE>
Costs included in development costs to develop proved  undeveloped  reserves for
the years ended  December  31,  2003,  2002 and 2001 were $49.4  million,  $11.0
million and $19.9 million, respectively.

<TABLE>
<CAPTION>
Results of Operations from Gas and Oil Producing Activities*
-------------------------------------------------------------------------------------------------------
                                                                   (In Thousands of Dollars)
-------------------------------------------------------------------------------------------------------
At December 31,                                             2003              2002              2001
-------------------------------------------------------------------------------------------------------
<S>                                                       <C>               <C>               <C>
Revenues                                               $   497,948         $ 356,233         $ 404,584
-------------------------------------------------------------------------------------------------------
Production and lifting costs                                63,591            44,822            37,574
Shipping and handling costs                                 10,388             9,450             7,850
Depletion                                                  205,118           177,548           173,566
-------------------------------------------------------------------------------------------------------
Total expenses                                             279,097           231,820           218,990
-------------------------------------------------------------------------------------------------------
Income before taxes                                        218,851           124,414           185,594
Income taxes                                                76,598            42,519            64,118
-------------------------------------------------------------------------------------------------------
Results of operations                                  $   142,253         $  81,895         $ 121,476
-------------------------------------------------------------------------------------------------------
</TABLE>
*    (Excluding corporate overhead and interest costs)


                                      155
<PAGE>


<TABLE>
<CAPTION>
Summary of Production and Lifting Costs
----------------------------------------------------------------------------------------------------------------------
                                                                                    (In Thousands of Dollars)
----------------------------------------------------------------------------------------------------------------------
At December 31,                                                               2003             2002             2001
----------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>              <C>              <C>
Pumping, gauging and other labor                                           $ 10,975         $  7,846         $  5,342
Compressors and other rental equipment                                        5,136            4,135            3,023
Property taxes and insurance                                                  7,155            6,801            3,640
Transportation                                                                2,329            2,131            3,162
Processing fees                                                               2,354            3,078            2,267
Workover and well stimulation                                                 5,225            2,348            1,478
Repairs, maintenance and supplies                                             3,735            2,972            2,204
Fuel and chemicals                                                            3,109            2,582            1,424
Environmental, regulatory and other                                           7,614            3,307            3,639
Severance taxes                                                              15,959            9,622           11,395
----------------------------------------------------------------------------------------------------------------------
Total production and lifting costs                                         $ 63,591         $ 44,822         $ 37,574
----------------------------------------------------------------------------------------------------------------------
</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,                                                   2003              2002              2001
-------------------------------------------------------------------------------------------------------------
<S>                                                            <C>               <C>                <C>
Proved Reserves
   Beginning of year                                             614,734           585,659           545,858
   Revisions of previous estimates                               (32,433)          (15,324)          (39,994)
   Extensions and discoveries                                    140,632           105,798            86,401
   Production                                                   (100,130)         (107,507)          (90,754)
   Purchases of reserves in place                                 89,380            48,777            84,148
   Sales of reserves in place                                          -            (2,669)                -
-------------------------------------------------------------------------------------------------------------
Proved reserves - End of year (1)                                712,183           614,734           585,659
Proved developed reserves
   Beginning of year                                             435,629           448,921           431,536
   End of Year (2)                                               488,012           435,629           448,921
-------------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Includes minority interest of 318,417,  208,516, and 188,077 in 2003, 2002,
     and 2001, respectively.

(2)  Includes  minority interest of 218,190,  148,811 and 148,593 in 2003, 2002,
     and 2001, respectively.



                                      156
<PAGE>


<TABLE>
<CAPTION>
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
----------------------------------------------------------------------------------------------------------
At December 31,                                                2003                 2002             2001
----------------------------------------------------------------------------------------------------------
<S>                                                          <C>                 <C>               <C>
Proved reserves
Beginning of Year                                              9,548              10,234            7,912
Revisions of previous estimates                               (3,542)                 (5)            (289)
Extension and discoveries                                        117                 342            3,061
Production                                                    (1,514)             (1,025)            (536)
Purchases of reserves in place                                 3,753                 483              115
Sales of reserves in place                                         -                (481)             (29)
----------------------------------------------------------------------------------------------------------
Proved reserves - End of year (1)                              8,362               9,548           10,234
Proved developed reserves
Beginning of year                                              2,413               2,479            2,126
End of year (2)                                                4,273               2,413            2,479
----------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Includes  minority  interest of 3,739,  2,256 and 2,186 in 2003,  2002, and
     2001, respectively.

(2)  Includes  minority  interest of 1,910, 824 and 821 in 2003, 2002, and 2001,
     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,                                                              2003                    2002                   2001
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>                    <C>                     <C>
Future cash flows                                                        $ 4,375,781            $ 2,951,622             $ 1,580,077
Future costs-
Production                                                                  (769,892)              (495,097)               (316,421)
Development                                                                 (378,547)              (263,926)               (227,158)
------------------------------------------------------------------------------------------------------------------------------------
Future net inflows before income tax                                       3,227,342              2,192,599               1,036,498
Future income taxes                                                         (853,425)              (559,853)               (221,324)
------------------------------------------------------------------------------------------------------------------------------------
Future net cash flows                                                      2,373,917              1,632,746                 815,174
10% discount factor                                                         (853,403)              (528,829)               (228,988)
------------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows (1)             $ 1,520,514            $ 1,103,917             $   586,186
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Includes minority interest of $672,620, $361,435 and $182,555 in 2003, 2002
     and 2001, respectively

Costs  included  in future  development  costs  related  to  proved  undeveloped
reserves  for the  years  ending  December  31,  2004,  2005 and 2006 are  $96.3
million, $135.4 million, and $10.5 million, respectively.


                                      157
<PAGE>


<TABLE>
<CAPTION>
 Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserve Quantities
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                        (In Thousands of Dollars)
-----------------------------------------------------------------------------------------------------------------------------------
 At December 31,                                                             2003                   2002                    2001
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>                    <C>                     <C>
 Standardized measure - beginning of year                               $ 1,103,917            $   586,186             $ 2,165,759
 Sales and transfers, net of production costs                              (492,328)              (285,603)               (359,163)
 Net change in sales and transfer prices, net
      of production costs                                                   384,299                589,632              (2,250,252)
 Extensions and discoveries and improved
      recovery, net of related costs                                        434,311                242,055                 117,326
 Changes in estimated future development costs                               (9,352)                (6,453)                (23,395)
 Development costs incurred during the period
      that reduced future development costs                                  81,025                 42,075                  75,652
 Revisions of quantity estimates                                           (123,954)               (36,368)                (52,928)
 Accretion of discount                                                      142,296                 68,986                 293,581
 Net change in income taxes                                                (236,551)              (215,369)                666,373
 Net purchases of reserves in place                                         254,030                 99,741                  51,674
 Sales of reserves in place                                                       -                (31,488)                   (133)
 Changes in production rates (timing) and other                             (17,179)                50,523                 (98,308)
-----------------------------------------------------------------------------------------------------------------------------------
 Standardized measure - end of year                                     $ 1,520,514            $ 1,103,917              $  586,186
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
Average Sales Prices and Production Costs Per Unit
---------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,                                                           2003              2002              2001
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>               <C>               <C>
Average Sales Price*
     Natural gas ($/Mcf)                                                          5.23              3.16              4.09
     Oil, condensate and natural gas liquid ($/Bbl)                              28.26             24.06             23.09
Production cost per equivalent Mcf ($)                                            0.58              0.42              0.40
---------------------------------------------------------------------------------------------------------------------------
</TABLE>
*Represents the cash price  received  which  excludes  the effect of any hedging
 transactions.





                                      158

<PAGE>


Acreage
------------------------------------------------------------------------------
At December  31, 2003                          Gross                    Net
------------------------------------------------------------------------------
Producing                                     638,425                 396,192
Undeveloped                                    464,874                388,830
------------------------------------------------------------------------------




Number of Producing Wells
-----------------------------------------------------------------------------
At December 31, 2003                          Gross                    Net
-----------------------------------------------------------------------------
Gas wells                                    2,435.0                 1,748.0
Oil wells                                       31.0                    15.9
-----------------------------------------------------------------------------


<TABLE>
<CAPTION>
Drilling Activity (Net)
-----------------------------------------------------------------------------------------------------------------------------------
At December 31,                                2003                              2002                             2001
-----------------------------------------------------------------------------------------------------------------------------------
                                Producing      Dry     Total        Producing     Dry    Total       Producing     Dry    Total
                              --------------------------------------------------------------------------------------------------
<S>                              <C>         <C>     <C>             <C>         <C>     <C>          <C>        <C>      <C>
Net developmental wells           84.4        20.0    104.4           65.1        9.4     74.5         51.9       10.2     62.1
Net exploratory wells              5.4         7.0     12.4            4.0        2.2      6.2          5.3        4.3      9.6
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


-----------------------------------------------------------------------------
At December 31, 2003                           Gross                     Net
-----------------------------------------------------------------------------
Exploratory                                     4.0                      3.3
Developmental                                  12.0                      9.2
-----------------------------------------------------------------------------





                                      159
<PAGE>


Note 17.  Summary of Quarterly Information (Unaudited)

The  following is a table of financial  data for each quarter of KeySpan's  year
ended December 31, 2003.

<TABLE>
<CAPTION>
                                                                                                      Quarter Ended
--------------------------------------------------------------------------------------------------------------------------------
         (In Thousands of Dollars, Except Per Share Amounts)         3/31/2003        6/30/2003       9/30/2003       12/31/2003
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>             <C>              <C>             <C>
Operating revenues                                                   2,512,525       1,408,152        1,131,814       1,862,670
Operating income                                                       456,694         138,229          107,923         338,811
Earnings (loss) from continuing operations                             243,091          (5,938)          12,585         174,443
Cumulative change in accounting principle                                  174               -                -         (37,625)
Earnings (loss) for common stock                                       241,804          (7,399)          11,124         135,357
Basic earnings per common share from continuing
  operations less preferred stock dividends (a)                           1.54           (0.05)            0.07            1.08
Change in accounting principle (a)                                           -               -                -           (0.23)
Basic earnings per common share (a)                                       1.54           (0.05)            0.07            0.85
Diluted earnings per common share (a)                                     1.53           (0.05)            0.07            0.84
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, 2002.

<TABLE>
<CAPTION>
                                                                                          Quarter Ended
--------------------------------------------------------------------------------------------------------------------------------
             (In Thousands of Dollars, Except Per Share Amounts)    3/31/2002       6/30/2002        9/30/2002       12/31/2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>              <C>             <C>              <C>
Operating revenues                                                  1,873,577        1,218,201       1,078,336        1,800,552
Operating income                                                      406,038          115,383          97,692          322,969
Earnings from continuing operations                                   214,631           29,174           4,964          148,581
Earnings (loss) from discontinued 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
  discontinued 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.


                                      160

<PAGE>


INDEPENDENT AUDITORS' REPORT

To the Shareholders and Board of Directors of KeySpan Corporation:

We  have  audited  the  accompanying  Consolidated  Balance  Sheets  of  KeySpan
Corporation and subsidiaries (the Company) as of December 31, 2003 and 2002, and
the related Consolidated Statements of Income, Retained Earnings,  Comprehensive
Income,  Capitalization,  and Cash Flows for each of the two years in the period
ended  December 31, 2003.  Our audits also included the  consolidated  financial
statement  schedule,  for each of the two years in the period ended December 31,
2003, included in the Index in Item 15. 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  statement
schedule  based  on  our  audits.  The  consolidated  financial  statements  and
consolidated  financial  statement schedule of KeySpan  Corporation for the year
ended  December  31,  2001  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 audits 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  audits  provide  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,  2003  and  2002,  and the  results  of their
operations  and their cash  flows for each of the two years in the period  ended
December 31, 2003, in conformity with accounting  principles  generally accepted
in the  United  States  of  America.  Also  in our  opinion,  such  consolidated
financial  statement  schedule,  for each of the two years in the  period  ended
December  31,  2003,  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(G) to the consolidated  financial statements,  on January
1, 2002,  the  Company  adopted  Statement  of  Financial  Accounting  Standards
("SFAS") No. 142,  "Goodwill  and Other  Intangible  Assets,"  (SFAS No. 142) to
change its method of accounting for goodwill and other intangibles. As discussed
in Note 1(N) and Note 1(P),  on January 1, 2003,  the Company  adopted  SFAS No.
148,  "Accounting for Stock-Based  Compensation - Transition and Disclosure" and
SFAS No. 143  "Accounting  for Asset  Retirement  Obligations"  (SFAS No.  143),
respectively. Also, as discussed in Note 1(P), on December 31, 2003, the Company
adopted  FASB  Interpretation  No.  46,   "Consolidation  of  Variable  Interest
Entities, an Interpretation of ARB No. 51" (FIN 46).


                                      161
<PAGE>


As discussed above, the consolidated  financial  statements of the Company as of
December 31, 2001 were audited by other auditors who have ceased operations. The
notes related to these consolidated  financial statements have been revised from
those originally issued to include the transitional disclosures required by SFAS
No.  142,  SFAS No.  143 and FIN 46,  which were  adopted  by the  Company as of
January 1, 2002, January 1, 2003 and December 31, 2003, respectively.  Our audit
procedures  with respect to the  disclosures  in Note 1(G) for 2001 included (i)
agreeing  the  previously  reported  earnings  for  common  shareholders  to the
previously  issued  consolidated  financial  statements  and the  adjustments to
earnings for common shareholders 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. Our audit procedures
with respect to the  disclosures in Note 1(P) for 2001 included (i) agreeing the
previously   reported  earnings  for  common  stock  to  the  previously  issued
consolidated  financial  statements  and the  adjustments to earnings for common
stock representing  accretion,  cost of removal and amortization  expense to the
Company's  underlying  records  obtained from  management,  and (ii) testing the
mathematical  accuracy of the  reconciliation  of Earnings  for Common  Stock to
reported pro forma  earnings,  and the related  earnings-per-share  amounts.

In addition,  the 2001 consolidated  financial statements have also been revised
from those originally issued to reflect certain  reclassifications  as discussed
in Note  1(B).  These  reclassifications  have  been  made  to the  Consolidated
Statement  of  Income  and the  Consolidated  Statement  of Cash  Flows.  On the
Consolidated  Statement  of Income,  "Income from Equity  Investments"  has been
reclassified  from a component of "Other Income and (Deductions)" to a component
of  "Operating  Income."  On the  Consolidated  Statement  of Cash  Flows,  "Net
Income," "Minority  Interest,"  "Changes in Assets and Liabilities - Other," and
"(Gain) Loss on Disposal of Subsidiary  Stock"  amounts have been  reclassified.
Our audit  procedures with respect to such  reclassifications  for 2001 included
(i)  agreeing  the  amount  to  the  previously  issued  consolidated  financial
statements,  and (ii)  testing the  mathematical  accuracy  of the  consolidated
financial statements.

In  our  opinion,   the   adjustments   in  Note  1(G),   Note  1(P),   and  the
reclassifications  reflected in the  Consolidated  Statements of Income and Cash
Flows are  appropriate  and have been  properly  applied.  However,  we were not
engaged  to  audit,  review,  or apply  any  procedures  to the  2001  financial
statements  of the  Company  other  than with  respect to such  adjustments  and
reclassifications  and,  accordingly,  we do not express an opinion or any other
form of assurance on the 2001 financial statements taken as a whole.

/s/Deloitte & Touche LLP
February 18, 2004
New York, New York



                                      162
<PAGE>



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholder 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 KeySpan  Corporation's
management.  Our  responsibility  is to express  an  opinion on these  financial
statements based on our audits.

We conducted our audit 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 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  Andersen LLP completed
its last  post-audit  review of the December 31,  2001,  consolidated  financial
information on April 29, 2002.






                                      163
<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 three fiscal years,
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 three fiscal years, 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.

Item 9A.    Controls and Procedures

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

An  evaluation  of  the  effectiveness  of  KeySpan's  disclosure  controls  and
procedures as of December 31, 2003 was conducted  under the supervision and with
the  participation  of KeySpan's  Chief  Executive  Officer and Chief  Financial
Officer.  Based on that evaluation,  KeySpan's Chief Executive Officer and Chief
Financial  Officer  have  concluded  that  KeySpan's   disclosure  controls  and
procedures  were  adequate  and  designed  to ensure that  material  information
relating to KeySpan and its consolidated subsidiaries would be made known to the
Chief  Executive  Officer and Chief  Financial  Officer by others  within  those
entities,  particularly  during the  periods  when  periodic  reports  under the
Exchange  Act are  being  prepared.  Furthermore,  there  has been no  change in
KeySpan's  internal control over financial  reporting,  identified in connection
with the evaluation of such control,  that occurred during KeySpan's last fiscal
quarter that has  materially  affected,  or is  reasonably  likely to materially
affect,  KeySpan's  internal  control  over  financial  reporting.  Refer to the
Certifications  by KeySpan's Chief Executive Officer and Chief Financial Officer
filed as exhibits 31.1 and 31.2 to this report.


                                    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 25,
2004 (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,  Certain  Relationships  and
Related Transactions",  "Committees of the Board", "Code of Ethics" and "Section
16(a)  Beneficial  Ownership  Reporting   Compliance"  contained  in  the  Proxy
Statement, which information is incorporated herein by reference thereto.


                                      164
<PAGE>


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  and  Item  5 of  this  report,  which  information  is
incorporated herein by reference thereto.

Item 13.    Certain Relationships and Related Transactions

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

Item 14.    Principal Accounting Fees and Services

The information  required by this item is set forth under the caption  "Proposal
2.  Ratification  of Deloitte & Touche LLP as Independent  Public  Accountants,"
"Fiscal Year 2003 Audit Firm Fee Summary" and "Report of the Audit Committee" in
the Proxy Statement, which information is incorporated by reference thereto.

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

(a)         Required Documents

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, 2003, the
     year ended December 31, 2002, and the year ended December 31, 2001
o    Consolidated Statement of Retained Earnings for the year ended December 31,
     2003,  the year ended  December 31, 2002,  and the year ended  December 31,
     2001
o    Consolidated Balance Sheet at December 31, 2003 and December 31, 2002
o    Consolidated  Statement of Capitalization at December 31, 2003 and December
     31, 2002
o    Consolidated  Statement of Cash Flows for the year ended December 31, 2003,
     the year ended December 31, 2002, and the year ended December 31, 2001
o    Consolidated  Statement of Comprehensive Income for the Year ended December
     31, 2003,  the year ended December 31, 2002 and the year ended December 31,
     2001
o    Notes to Consolidated Financial Statements
o    Independent Auditors' Report


                                      165
<PAGE>


2.          Financial Statement Schedules

Consolidated  Schedule of Valuation and  Qualifying  Accounts for the year ended
December 31, 2003, the year ended December 31, 2002, and the year ended December
31, 2001.
<TABLE>
                  SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                            Column A                Column B                   Column C                  Column D        Column E
                                                                              Additions
------------------------------------------------------------------------------------------------------------------------------------
                          Descriptions             Balance at        Charged to       Acquisitions         Net           Balance at
                                                  Beginning of       costs and                          Deductions         End of
                                                     Period           expenses                                             Period
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                 <C>                 <C>                 <C>           <C>              <C>
------------------------------------------
Twelve Months Ended December 31, 2003
------------------------------------------

     Deducted from asset accounts:
          Allowance for doubtful accounts     $       63,029     $       82,120     $        -     $       65,965     $      79,184

     Additions to liability accounts:
          Reserve for injury and damages      $       25,780     $        3,928     $        -     $       20,338     $       9,370
          Reserve for environmental
            expenditures                      $      232,146     $      106,270     $        -     $       43,725     $     294,691

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

     Additions to liability accounts:
          Reserve for injury and damages      $       20,880     $       11,984     $        -     $        7,084     $      25,780
          Reserve 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
          Reserve for environmental
            expenditures                      $      157,507     $      115,942     $        -     $       15,800     $     257,649
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
All other  schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.


                                      166
<PAGE>


(b)         Reports on Form 8-K

In our report on Form 8-K dated  November 6, 2003, we disclosed that we issued a
press release concerning, among other things, our earnings for the third quarter
ended September 30, 2003.

In our report on Form 8-K dated December 18, 2003, we disclosed that we issued a
press  release  disclosing,  among  other  things,  our  expectations  for  2004
earnings.

In our report on Form 8-K dated  February 5, 2004, we disclosed that we issued a
press release concerning,  among other things, our consolidated earnings for the
year ended December 31, 2003.

(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 as of June 25, 2003, as amended (filed
          as Exhibit 3.1 to the  Company's  Form 10-Q for the  quarterly  period
          ended June 30, 2003)

4.1-a     Indenture,  dated as of November 1, 2000, between KeySpan  Corporation
          and the Chase Manhattan Bank, as Trustee, with 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)


                                      167

<PAGE>


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       Credit Agreement among KeySpan  Corporation,  the several Lenders, ABN
          AMRO Bank,  N.V., as Syndication  Agent,  Bank One, N. A. and Wachovia
          Bank, N.A, as Co-Documentation  Agents, and J.P. Morgan Chase Bank, as
          Administrative  Agent  for $450  million,  dated  as of June 27,  2003
          (filed as Exhibit  4.1 to the  Company's  Form 10-Q for the  quarterly
          period ended June 30, 2003)

4.4       Credit  Agreement  among  KeySpan  Corporation,  the several  Lenders,
          Citibank  N.A., as Syndication  Agent,  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 $850 million, dated as of June
          27,  2003  (filed as Exhibit  4.1 to the  Company's  Form 10-Q for the
          quarterly period ended June 30, 2003)

4.5-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)

4.5-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)

4.5-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)

4.5-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)


                                      168
<PAGE>


4.6-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)

4.6-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)

4.7-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)

4.7-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)

4.8-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)

4.8-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)

4.9-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)

4.9-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)

4.10-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)


                                      169
<PAGE>


4.10-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)

4.11-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)

4.11-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)

4.11-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)

4.12-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)

4.12-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)

4.13-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)

4.13-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)

4.14-a*   Lease  Agreement,  dated as of  November  1, 2003,  by and between the
          Suffolk  County   Industrial   Development   Agency  and  KeySpan-Port
          Jefferson Energy Center, LLC

4.14-b*   Company Lease Agreement,  dated as of November 1, 2003, by and between
          KeySpan-Port  Jefferson  Energy  Center,  LLC and the  Suffolk  County
          Industrial Development Agency

4.14-c*   Guaranty,  dated as of November 26, 2003, from KeySpan  Corporation to
          the Suffolk County Industrial Development Agency


                                      170
<PAGE>


4.15-a*   Lease  Agreement,  dated as of  November  1, 2003,  by and between the
          Nassau  County  Industrial  Development  Agency  and  KeySpan-Glenwood
          Energy Center, LLC

4.15-b*   Company Lease Agreement,  dated as of November 1, 2003, by and between
          KeySpan-Glenwood  Energy Center,  LLC and the Nassau County Industrial
          Development Agency

4.15-c*   Guaranty,  dated as of November 26, 2003, from KeySpan  Corporation to
          the Nassau County Industrial Development Agency

4.16      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))

4.17      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
          Statement (File No. 33-31869))

4.18      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)

4.19      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)

4.20      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)

4.21      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)

4.22      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)

4.23      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)

4.24      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)


                                      171
<PAGE>


4.25      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  Natural  Gas,  Inc.'s Form 10-K for the fiscal year ended
          September 30, 1989 (File No. 0-11035))

4.26      Third  Supplemental  Indenture,  dated as of September 1, 1990, to Gas
          Service, Inc.'s General and Refunding Mortgage Indenture,  dated as of
          June 30, 1987 (filed as Exhibit 4.2 to EnergyNorth Natural Gas, Inc.'s
          Form 10-K for the  fiscal  year  ended  September  30,  1990 (File No.
          0-11035))

4.27      Fourth  Supplemental  Indenture,  dated as of January 10, 1992, to Gas
          Service, Inc.'s General and Refunding Mortgage Indenture,  dated as of
          June 30, 1987 (filed as Exhibit 4.3 of EnergyNorth Natural Gas, Inc.'s
          Form 10-K for the  fiscal  year  ended  September  30,  1992 (File No.
          0-11035))

4.28      Fifth  Supplemental  Indenture,  dated as of February 1, 1995,  to Gas
          Service, Inc.'s General and Refunding Mortgage Indenture,  dated as of
          June 30, 1987 (filed as Exhibit 4.4 to EnergyNorth Natural Gas, Inc.'s
          Form 10-K for the  fiscal  year  ended  September  30,  1996 (File No.
          1-11441))

4.29      Sixth Supplemental  Indenture,  dated as of September 15, 1997, to Gas
          Service, Inc.'s 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)

4.30      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))

4.31      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% Series due 2020 (filed as Exhibit 4-14 to Essex
          Gas Company's Form 10-Q for the quarter ended February 28, 1991)

4.32      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 % Series due 2017  (filed as Exhibit  4.5 to the
          Essex Gas Company's Form 10-Q for the quarter ended February 28, 1997)

4.33      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 Essex Gas  Company's  Form 10-Q for the  quarter  ended
          February 28, 1991)

4.34*     Letter of Credit and  Reimbursement  Agreement dated December 9, 2003,
          by and between KeySpan  Generation LLC and Royal Bank of Scotland Bank
          PLC


                                      172
<PAGE>


4.35      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))

4.36      Indenture,  dated as of June 10, 2003, between The Houston Exploration
          Company and the Bank of New York,  as Trustee,  with respect to the 7%
          Senior  Subordinated  Notes due 2013.  (filed  as  Exhibit  4.2 to The
          Houston Exploration Company's  Registration Statement on Form S-4 (No.
          333-106836)

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  Annual Report on 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)


                                      173
<PAGE>


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  Annual Report on 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)

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 July 1, 2002 between KeySpan
          and Gerald  Luterman  (filed as Exhibit 10.11 to the Company's  Annual
          Report on Form 10-K for the year ended December 31, 2002)


10.12**   Supplemental  Retirement  Agreement dated July 1, 2002 between KeySpan
          and  Steven L.  Zelkowitz  (filed as  Exhibit  10.12 to the  Company's
          Annual Report on Form 10-K for the year ended December 31, 2002)


10.13**   Supplemental  Retirement  Agreement dated July 1, 2002 between KeySpan
          and David J. Manning  (filed as Exhibit 10.13 to the Company's  Annual
          Report on Form 10-K for the year ended December 31, 2002)

10.14**   Supplemental  Retirement  Agreement dated July 1, 2002 between KeySpan
          and Neil  Nichols  (filed as  Exhibit  10.14 to the  Company's  Annual
          Report on Form 10-K for the year ended December 31, 2002)

10.15**   Supplemental  Retirement  Agreement dated July 1, 2002 between KeySpan
          and Elaine  Weinstein  (filed as Exhibit 10.15 to the Company's Annual
          Report on Form 10-K for the year ended December 31, 2002)


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<PAGE>


10.16** * Directors'  Deferred  Compensation Plan effective April 2003

10.17**   Officers'  Deferred Stock Unit Plan of KeySpan  Corporation  (filed as
          Exhibit 10.17 to the Company's Annual Report on 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 Annual Report on 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 29, 2003

10.21**   KeySpan's  Amended Long Term Performance  Incentive  Compensation Plan
          (filed as Exhibit A to the  Company's  2001 Proxy  Statement  filed 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 filed on
          March 30, 1999)

10.23     Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for
          the  Ravenswood  Generating  Plants and Gas Turbines dated January 28,
          1999, between the Company 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 Agreement between KeySpan-Ravenswood, LLC
          and LIC Funding, Limited Partnership, dated as of June 27, 2002 (filed
          as Exhibit 10.25 to the  Company's  Annual Report on 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  Annual Report on Form 10-K for the year ended  December 31,
          2002)


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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-a   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)

10.29-b   First  Amendment  to Credit  Agreement  among The Houston  Exploration
          Company, the lenders Wachovia Bank, National  Association,  as issuing
          bank and as  administrative  agent,  The Bank of Nova Scotia and Fleet
          National  Bank,  as  co-syndication   agents;  and  BNP  Paribas,   as
          documentation agent,  effective June 5, 2003 (filed as Exhibit 10.1 to
          The Houston  Exploration  Company's  Quarterly Report on Form 10-Q for
          the quarter ended June 30, 2003 (File No. 001-11899)).

10.29-c   Second  Amendment to Credit  Agreement  among The Houston  Exploration
          Company,   the  lenders  named  therein,   Wachovia   Bank,   National
          Association,  as issuing bank and as administrative agent, The Bank of
          Nova Scotia and Fleet National Bank, as co-syndication agents; and BNP
          Paribas, as documentation agent, effective September 3, 2003 (filed as
          Exhibit 10.1 to The Houston Exploration  Company's Quarterly Report on
          Form  10-Q  for  the  quarter  ended  September  30,  2003  (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


                                      176
<PAGE>


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

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)

10.33     Registration  Rights  Agreement  dated as of July 2, 1996  between The
          Houston  Exploration Company and THEC Holdings Corp. (filed as Exhibit
          10.13 to The Houston Exploration Company's  Registration  Statement on
          Form S-1 (Registration No. 333-4437))

10.34     Registration  Rights Agreement between The Houston Exploration Company
          and Smith Offshore  Exploration Company (filed as Exhibit 10.15 to The
          Houston  Exploration  Company's  Registration  Statement  on Form  S-1
          (Registration No. 333-4437))

10.35     Registration  Rights  Agreement  dated as of June 5,  2003,  among The
          Houston  Exploration  Company and Wachovia  Securities,  Inc.,  Lehman
          Brothers Inc., BNP Paribas  Securities Corp.,  Fleet Securities,  Inc.
          and Scotia Capital (USA) Inc., as Initial Purchasers.  (Exhibit 4.5 to
          The Houston Exploration Company's  Registration  Statement on Form S-4
          (Registration No. 333-106836))

12*       Computation  in  support of  earnings  to fixed  charges  and ratio of
          combined fixed charges and dividends

14*       Code of Ethics

21*       Subsidiaries of the Registrant

23.1*     Consent of Deloitte & Touche LLP, Independent Auditors


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<PAGE>


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 Andrea S. Christensen on March 10, 2004

24.2*     Power of Attorney executed by Alan H. Fishman on March 10, 2004

24.3*     Power of Attorney executed by J. Atwood Ives on March 10, 2004

24.4*     Power of Attorney executed by James R. Jones on March 10, 2004

24.5*     Power of Attorney executed by James L. Larocca on March 10, 2004

24.6*     Power of Attorney executed by Gloria C. Larson on March 10, 2004

24.7*     Power of Attorney executed by Stephen W. McKessy on March 10, 2004

24.8*     Power of Attorney executed by Edward D. Miller on March 10, 2004

24.9*     Certified copy of the Resolution of the Board of Directors authorizing
          signatures pursuant to power of attorney

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

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

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

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

* filed herewith
** compensation agreement






                                      178
<PAGE>




                                   SIGNATURES

     Pursuant to the  requirements  of the  Securities  Exchange Act of 1934, as
amended,  this  report has been  signed by the  registrant  and on behalf of the
registrant by the following persons in the capacities indicated.


                                         KEYSPAN CORPORATION

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





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

By:/s/  Robert B. Catell
------------------------


Gerald Luterman                     Executive Vice President and
                                    Chief Financial Officer

By:/s/ Gerald Luterman
----------------------


Joseph F. Bodanza                   Senior Vice President and
                                    Chief Accounting Officer

By:/s/Joseph F. Bodanza
-----------------------


            *
--------------------
Andrea S. Christensen               Director

            *
--------------------
Alan H. Fishman                     Director

            *
--------------------
J. Atwood Ives                      Director

            *
--------------------
James R. Jones                      Director




                                      179
<PAGE>


            *
--------------------
Gloria C. Larson                    Director

            *
--------------------
James L. Larocca                    Director

            *
--------------------
Stephen W. McKessy                  Director

            *
--------------------
Edward D. Miller                    Director



--------------------
Vikki Pryor                         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.




                                      180