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, 2004

                         Commission File Number 1-14161

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

             NEW YORK                                   11-3431358
 (State or other jurisdiction of            (I.R.S. employer identification no.)
  incorporation or organization)

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

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

           SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
      Title of each class              Name of each exchange on which registered
      -------------------              -----------------------------------------
   Common Stock, $.01 par value                  New York Stock Exchange
                                                 Pacific Stock Exchange

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

     SECURITIES  REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None (Title of
class) Indicate by check mark whether the registrant:  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days. 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, 2004, the aggregate market value of the common stock held by
non-affiliates  (160,169,624  shares) of the registrant was $5,878,225,201 based
on the closing price of the New York Stock  Exchange on such date, of $36.10 per
share.  For purposes of this  computation,  all  officers  and  directors of the
registrant are deemed to be affiliates.

     As of February 15, 2005,  there were  160,818,311  shares of common  stock,
$.01 par value, outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE

     Proxy  Statement  dated on or  about  March  29,  2005 is  incorporated  by
reference into Part III hereof.


<PAGE>


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

                                     PART II
Item 5.           Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
                   Equity Securities....................................................................................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 Mark Risk..............................................90
Item 8.           Financial Statements and Supplementary Data...........................................................93
Item 9.           Changes in and Disagreements with Accountants on Accounting and
                   Financial Disclosure................................................................................172
Item 9A.          Controls and Procedures..............................................................................172
Item 9B.          Other Information....................................................................................173

                                    PART III
Item 10.          Directors and Executive Officers of the Registrant...................................................175
Item 11.          Executive Compensation...............................................................................175
Item 12.          Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.......175
Item 13.          Certain Relationships and Related Transactions.......................................................175
Item 14.          Principal Accountant Fees and Services...............................................................175
Item 15.          Exhibits and Financial Statement Schedules ..........................................................176
</TABLE>



<PAGE>


                                     PART I

Item 1. 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 2.6 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 2,450  megawatt
Ravenswood electric generation facility (the "Ravenswood Facility"),  located in
Queens County in New York City,  which includes the 250 megawatt  combined cycle
generating  unit which began full  commercial  operation in May 2004, as well as
market generating capacity and energy to commercial retail customers.

The Energy Services segment provides  energy-related and fiber optic services to
customers   primarily  located  within  the  Northeastern  United  States,  with
concentrations  in the New  York  City and  Boston  metropolitan  areas  through
various  subsidiaries  that operate under the  following  principal two lines of
business: (i) Home Energy Services; and (ii) Business Solutions.  Management has
been reviewing the operating performance of this segment,  which has experienced
significantly lower operating profits than originally projected.  In January and
February of 2005,  we  disposed  of our  ownership  interests  in the  companies
engaged in mechanical contracting activities.

                                       1
<PAGE>


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

KeySpan's  strategic  vision  is  to  be  the  premier  energy  company  in  the
Northeastern United States.  KeySpan is the largest gas distribution  company in
the  Northeast and the fifth largest in the United  States.  KeySpan's  size and
scope enables 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 growth  opportunities for natural
gas  expansion in the Northeast by expanding  our  infrastructure,  primarily on
Long Island and in New England.

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  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.

The risks,  uncertainties  and factors that could cause actual results to differ
materially include but are not limited to:

-    volatility of fuel prices used to generate electricity;

-    fluctuations in weather and in gas and electric prices;

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

-    our  ability  to  successfully   manage  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  or  changes  in  accounting
     standards or GAAP which may require adjustment to financial statements;

-    inflationary trends and interest rates;

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

-    available sources and cost of fuel;

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


                                       2
<PAGE>


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

-    retention of key personnel;

-    federal,  state and local  regulatory  initiatives  that  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,  state and local  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 facing our unregulated Energy Services businesses;

-    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;

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

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

-    timely receipts of payments from LIPA and the New York  Independent  System
     Operator ("NYISO"), our two largest customers;

-    the outcome of LIPA's strategic  business options study,  pertaining to its
     long-term future which include, as stated by LIPA, whether or not LIPA will
     continue its  operations as they presently  exist,  fully  municipalize  or
     privatize,  sell some,  but not all of its assets and/or become a regulator
     of rates and services,  or merge with one or more  utilities.  In addition,
     LIPA must make a  determination  by May 28,  2005,  as to  whether  it will
     purchase  our  interest in KeySpan  Generation  LLC,  the owner of our Long
     Island  (excluding  the Glenwood and Port  Jefferson  Energy  Center units)
     generating assets,  pursuant to the terms of the Generation Purchase Rights
     Agreement; 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.


                                       3
<PAGE>


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 an Ethical  Business Conduct  Statement
applicable to all  directors,  officers and employees of the Company as required
by securities rules and regulations.

KeySpan's  Code  of  Ethics,  Ethical  Business  Conduct  Statement,   Corporate
Governance  Guidelines,   the  Corporate  Governance  and  Nominating  Committee
Charter,  the Compensation and Management  Development  Committee  Charter,  the
Audit  Committee  Charter and the  Executive  Committee  Charter  (collectively,
"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.

                            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  2.6 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 1.68
million  customers.  In  Massachusetts,  Boston Gas,  Colonial Gas and Essex Gas
serve three contiguous service territories  consisting of 1,934 square miles and
approximately  792,000  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
80,000  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  23,336 miles of gas mains and
distribution pipelines.


                                       4
<PAGE>


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 either
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  maintain a diverse
portfolio  of firm gas supply,  storage  and  pipeline  transportation  capacity
contracts to adequately serve the  requirements of our gas sales  customers,  to
maintain system reliability and system operations, and to meet our obligation to
serve. 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.

KeySpan  actively  promotes a competitive  retail gas market by offering  tariff
firm  transportation  services to firm gas customers who elect to purchase their
gas supplies  from natural gas marketers  rather than from the utility.  KeySpan
further  facilitates   competition  by  releasing  its  pipeline  transportation
capacity and  offering  bundled gas supply to natural gas  marketers  that would
otherwise not be able to obtain their own capacity,  and are not participants of
mandatory capacity assignment programs in Massachusetts and New Hampshire.

KeySpan also participates in interstate  markets by releasing  pipeline capacity
and by selling bundled gas services to customers  located outside of our service
territory ("off-system" customers).

KeySpan  purchases  natural  gas for  firm gas  customers  under  both  long and
short-term  supply  contracts,  as well as on the spot market,  and utilizes its
firm  pipeline  transportation  contracts to transport the gas from the point of
purchase to the market.  KeySpan also contracts for firm capacity in natural gas
underground  storage  facilities  to store  gas  during  the  summer  for  later
withdrawal  during the winter heating season when gas customer demand is higher.
KeySpan  also  contracts  for firm  winter  peaking  supplies  to meet  firm gas
customer demand on the coldest days of the year.

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


                                       5
<PAGE>


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.

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 2,115 MDTH (one MDTH equals 1,000 DTH or 1 billion British Thermal
Units) of gas for a peak-day  during the 2004/05  winter season and that the gas
available  to us on such a peak-day  amounts to  approximately  2,190 MDTH.  The
highest  sendout day most recently  experienced  occurred on January 18, 2005 in
which the demand of the firm New York  customers was 1839 MDTH,  and the average
temperature was 13(0)F. Our New York firm gas peak-day  capability is summarized
in the following table:

<TABLE>
<CAPTION>
                                               MDTH per
Source                                            day                         % of Total
----------------------------------      -------------------------       ------------------------
<S>                                            <C>                              <C>
Pipeline                                          822                             38%
Underground Storage                               798                             36%
Peaking Supplies                                  570                             26%
                                                  ---                             ---
Total                                           2,190                            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
2004/05  winter,  approximately  80% of our New  York  natural  gas  supply  was
available from domestic sources and 20% from Canadian sources. We have available
under  firm  contract  822  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.


                                       6
<PAGE>


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.,  National  Fuel  and  Honeoye  Storage  Corporation
("Honeoye") for underground storage capacity of 60,456 MDTH and 798 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;  (ii) peaking supply  contracts with five dual-fuel
power producers  located in our franchise  areas; and (iii) three peaking supply
contracts with  suppliers  located  outside our franchise  area. For the 2004/05
winter season,  we have the capability to provide a maximum peaking  supplies of
570 MDTH on  excessively  cold  days.  The LNG plants  provide us with  peak-day
capacity of 394 MDTH and winter season  availability  of 2,053 MDTH. The peaking
supply  contracts  with the five  dual  fuel  power  producers  provide  us with
peak-day capacity of 176 MDTH and winter season availability of 4,146 MDTH.

Gas  Supply  Management.  We  have  an  agreement  with  Coral  Resources,  L.P.
("Coral"),  a subsidiary of Shell Oil Company,  under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI which expires on March 31, 2005. Upon expiration of
the agreement with Coral, we will perform these services with our own staff.

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, 2005, approximately 105,334 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.


                                       7
<PAGE>


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 in  Massachusetts  and 80 effective  degree
days in New Hampshire for peak-day demand. Under such criteria,  KEDNE estimates
that the  requirements  to  supply  their  firm gas  customers  would  amount to
approximately  1,351 MDTH of gas for a  peak-day  during  the  2004/2005  winter
season.  The gas  available  to KEDNE on such a peak-day  amounts to 1,420 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 1,456
MDTH.

The  highest  daily  throughput,   which  includes  both  firm  sales  and  firm
transportation,  to our New England  customers was 1,420 MDTH, which occurred on
January 15, 2004 at a level of 80 effective degree days. The total throughput of
1,420 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 2004/2005  winter season.  The
firm  gas  supply  peak-day  capability  of  KEDNE  for its  firm  customers  is
summarized in the following table:

<TABLE>
<CAPTION>
                                                  MDTH per
Source                                               day                       % of Total
-------------------------------------      -------------------------      -------------------------
<S>                                               <C>                             <C>
Pipeline                                             500                             35%
Underground Storage                                  248                             18%
Peaking Supplies                                     672                             47%
                                                   -----                            ----
Total                                              1,420                            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.  We have available
under firm contract 500 MDTH per day of year-round  and seasonal  transportation
capacity.  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.  In order to meet our  winter  demand  in the New  England
service  territories,  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 248 MDTH per day of maximum deliverability.


                                       8
<PAGE>


Peaking Supplies. The KEDNE gas supply portfolio is supplemented with peaking
supplies that are available on the coldest days throughout the winter season in
order to economically meet the increased requirements of our heating customers.
Peaking supplies include gas provided by both LNG and propane air plants located
within the distribution system, as well as four leased facilities located in
Providence, Rhode Island, and Lynn, Salem and Everett, Massachusetts. For the
2004/2005 winter season, on a peak-day, KEDNE has access to 672 MDTH of peaking
supplies, 47% of peak-day supply.

Gas Supply  Management.  The New  England  based gas  distribution  subsidiaries
operate under  portfolio  management  contracts with Merrill Lynch  Commodities,
formerly Entergy Koch Trading,  LP, ("Merrill  Lynch") that will expire on March
31,  2006.  Merrill  Lynch  provides  the  majority  of  the  city  gate  supply
requirements  to the four New England gas  distribution  companies  (Boston Gas,
Colonial Gas, Essex Gas and  EnergyNorth) at market prices and 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.

                           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, a recently  completed 250 MW combined cycle  generating
unit and 17 gas turbine  generators.  We also  operate and  maintain a 55 MW gas
turbine unit in Greenport,  Long Island under an agreement  with Hawkeye  Energy
Greenport, LLC.

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 pursuant to a management services agreement (the "MSA"); (ii) supply LIPA
with electric generating capacity, energy conversion and ancillary services from
our Long Island  generating  units  pursuant to a power  supply  agreement  (the
"PSA")  and  other  long-term  agreements  through  which we  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
pursuant to 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." In addition,  pursuant


                                       9
<PAGE>


to power purchase  agreements with LIPA, we supply electric  capacity and energy
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 MW 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,   KeySpan-Ravenswood,   LLC  ("KSR").  For  more  information
concerning  this lease  arrangement,  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."

In 2004, we completed the  construction  of a 250 MW combined  cycle  generating
unit at the Ravenswood Facility (the "Ravenswood Expansion"), thereby increasing
the total electric  capacity of the Ravenswood  Facility to 2,450 MW. In mid-May
2004, the Ravenswood Expansion began full commercial operations.  To finance the
Ravenswood  Expansion,  we entered into a leveraged lease financing  arrangement
pursuant to which the  Ravenswood  Expansion  was  acquired  by an  unaffiliated
lessor from KSR and  simultaneously  leased  back to it. This lease  transaction
qualifies  as an  operating  lease  under  SFAS  98.  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.

The Ravenswood  Facility,  including the Ravenswood  Expansion,  sells capacity,
energy and ancillary  services into the NYISO electricity market at market-based
rates, subject to mitigation. The Ravenswood Facility 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.

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-six of our  seventy-eight  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 instituted a program to reduce
nitrogen oxides for improved environmental performance while recovering 80 MW of
energy output.


                                       10
<PAGE>


The  following  table  indicates  the 2004  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           1711
Long Island City                          Combined Cycle                      Dual*                        1            222
Northport, L.I.                           Steam Turbine                       Dual*                        4           1549
Port Jefferson, L.I.                      Steam Turbine                       Dual*                        2            384
Glenwood, L.I.                            Steam Turbine                       Gas                          2            239
Island Park, L.I.                         Steam Turbine                       Dual*                        2            398
Far Rockaway, L.I.                        Steam Turbine                       Dual*                        1            111
Long Island City                          GT Units                            Dual*                       17            452
Glenwood and Port Jefferson Energy        GT Units                            Dual                         4            160
Center, L.I.
Throughout L.I.                           GT Units                            Dual*                       12            311
Throughout L.I.                           GT Units                            Oil                         30           1074
                                                                                                          --

TOTAL                                                                                                     78           6611
                                                                                                                       ----

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


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  LIPA   Agreements  and  subsequent   Power  Purchase
Agreements,  during  2004,  KeySpan  provided:  4,226  MW of  summer  generation
capacity and energy  conversion  services;  operation,  maintenance  and capital
improvement services for LIPA's T&D 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 the FERC in accordance with
the terms of the PSA. The prior FERC  approved  rates,  which had been in effect
since May 1998,  expired on  December  31,  2003.  On October 1, 2004,  the FERC
approved a settlement reached between KeySpan and LIPA with respect to new rates
and certain other costs and expenses.  Pursuant to the FERC approved settlement,
KeySpan's rates reflect a cost of equity of 9.5% with no revenue  increase.  The
FERC  also  approved  updated  operating  and  maintenance  expense  levels  and
KeySpan's  recovery of certain  other costs as agreed to by the  parties.  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


                                       11
<PAGE>



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 2004, we earned
$4 million in incentives under the PSA.

The PSA runs for an  original  term of 15 years,  expiring  in 2013.  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  purchases,  at fair  market  value,  all of
KeySpan's interest in KeySpan Generation LLC 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.

Generation  Purchase  Rights  Agreement.  Under an amended  Generation  Purchase
Rights Agreement  ("GPRA"),  LIPA has the right for a 6-month period,  beginning
November 29, 2004,  to acquire  KeySpan's  interest in KeySpan  Generation  LLC,
which includes 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.  We are
unable to predict  whether LIPA will  exercise its purchase  option  during this
period,  what the purchase  price would be or the effect of such purchase on our
financial condition, results of operations or cash flow.

Management  Services Agreement.  Under the MSA, we perform day-to-day  operation
and  maintenance  services  and  capital  improvements  on  LIPA's  T&D  system,
including,  among other functions,  T&D 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 T&D system.


                                       12
<PAGE>


In exchange for providing these services, we (i) are reimbursed for our budgeted
costs;  (ii) are entitled to earn an annual  management fee of $10 million;  and
(iii) 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 2004, we earned $7.4 million in
non-cost performance incentives. The MSA expires on December 31, 2008.

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 original
term for the fuel  supply  service  described  in (i)  above is  fifteen  years,
expiring May 28, 2013,  and the original term for the  off-system  purchases and
sales  services  described 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  purchased on behalf of LIPA. In 2004, we earned EMA
incentives in an aggregate of $5 million.

On December 9, 2004, LIPA issued a Request for Proposal ("RFP") for a new energy
manager to provide  system power supply  services  (commencing on May 29, 2006),
fuel procurement for Long Island  generating  facilities not acquired from LILCO
in 1998 and strategic fuel management  services,  commencing on January 1, 2006.
KeySpan intends to submit a bid to LIPA on or before March 1, 2005.

Power Purchase  Agreements.  KeySpan Glenwood Energy Center LLC and KeySpan Port
Jefferson  Energy Center LLC each have 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 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.

Other  Contingencies.  LIPA is in the process of  performing a strategic  review
initiative regarding its future direction. It has engaged a team of advisors and
consultants and is conducting public hearings to develop  recommendations  to be
submitted  to the LIPA  Trustees.  Some of the  strategic  options  that LIPA is
considering  include  whether  LIPA  should  continue  its  operations  as  they


                                       13
<PAGE>


presently exist, fully  municipalize or fully privatize,  sell some, but not all
of its assets and become a regulator of rates and services, or merge with one or
more utilities. In the near term, LIPA must make a determination by May 28, 2005
as to whether it will  exercise  its option to purchase  our interest in KeySpan
Generation  LLC  pursuant  to  the  terms  of  the  GPRA.  Until  LIPA  makes  a
determination  on its  future  direction,  we are unable to  determine  what the
impact will be on our financial condition, results of operations or cash flows.

Other Rights.  Pursuant to other  agreements  between LIPA and KeySpan,  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.

We own common plant assets (such as administrative office buildings and computer
systems)  formerly owned by LILCO and recover an allocable share of the carrying
costs of such plant assets 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 assets 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 (during the pendency 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 or liabilities which 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 PSA.

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.


                                       14
<PAGE>


                            Energy Services Overview

The Energy  Services  segment  includes  companies  that provide  energy-related
services to customers  primarily located within the northeastern  United States,
with  concentrations in the New York City and Boston  metropolitan areas through
the following two lines of business:  (i) Home Energy  Services,  which provides
residential customers and small commercial customers with installation,  service
and maintenance of energy systems and appliances;  and (ii) Business  Solutions,
which provides energy-related operation and maintenance, design, engineering and
consulting services to commercial and industrial customers.

The Energy  Services  segment has more than 1,000  employees  and  approximately
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 HVAC,  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.

As a result of an extremely  competitive market and sluggish economic conditions
within the construction  industry in the Northeastern  United States, the Energy
Services segment has experienced  significantly lower operating profits and cash
flows than originally  projected.  As previously  reported,  management has been
reviewing the operating performance of this segment. In November 2004, KeySpan's
Board of Directors authorized  management to begin the process of disposing of a
significant  portion of its ownership  interests in certain companies within the
Energy Services  segment - specifically  those  companies  engaged in mechanical
contracting  activities.  In the first quarter of 2005, the Company divested all
of its mechanical contracting subsidiaries.

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

Gas Exploration and Production

KeySpan is engaged in the exploration for and production of domestic natural gas
and oil through wholly-owned subsidiaries  Seneca-Upshur Petroleum,  Inc., d/b/a
KeySpan  Production  &  Development   Company   ("Seneca-Upshur")   and  KeySpan
Exploration and Production, LLC ("KeySpan Exploration and Production").  KeySpan
Exploration  and  Production  is  involved in a joint  venture  with The Houston
Exploration Company ("Houston Exploration") a former subsidiary of the Company.


                                       15
<PAGE>


In June 2004,  KeySpan reduced its ownership in Houston  Exploration from 55% to
23.5%,  through an exchange of 10.8  million  shares of its Houston  Exploration
common stock for 100% of the stock of  Seneca-Upshur,  previously a wholly owned
subsidiary of Houston Exploration.  Seneca-Upshur's assets consist of 50 billion
cubic  feet of low  risk,  mature,  onshore  gas  producing  properties  located
predominantly  in West  Virginia and  Pennsylvania.  In November  2004,  KeySpan
decided to sell its  remaining  ownership  interest  (approximately  6.6 million
shares  of  common  stock)  in  Houston  Exploration.  See Item 7.  Management's
Discussion  and Analysis of  Financial  Conditions  and Results of  Operations -
"Energy Investments" for a further discussion of these matters.

As indicated  above, as a result of the transactions  with Houston  Exploration,
Seneca-Upshur,  headquartered  in Buckhannon,  West Virginia,  owns and operates
onshore gas  producing  properties,  and operates  approximately  1,300 wells in
north  central West Virginia and southern  Pennsylvania.  To manage the inherent
volatility in commodity  prices,  Seneca-Upshur  entered into a three-year hedge
for a majority of its production at favorable prices.

As previously  indicated,  KeySpan  Exploration  and  Production is engaged in a
joint venture with Houston  Exploration  to explore for and produce  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  and
Production 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 and Production 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, KeySpan Exploration and
Production  sold its interest in the  gas-producing  assets in the joint venture
drilling program to Houston  Exploration.  KeySpan  Exploration and Production's
remaining  joint venture assets are primarily  proved  undeveloped  oil reserves
located off the Gulf of Mexico in the South Timbalier and Mustang Island areas.

Domestic Pipelines and Gas Storage Facilities

We own a 20.4% interest in Iroquois Gas Transmission  System LP, the partnership
that owns a  411-mile  pipeline  that can bring up to  1,176,000  DTH per day of
Canadian  gas  supply  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 312,000 DTH of gas per day.

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,  under Long Island
Sound, to a terminus near Shoreham, Long Island.  Applications for all necessary
regulatory  authorizations  were  filed  in 2000  and  2001.  Islander  East has
received a final  certificate  from the FERC and all necessary  permits from the
State of New York. The State of Connecticut denied Islander East's  applications
for  coastal   zone   management   and  Section  401  of  the  Clean  Water  Act
authorizations.  Islander East appealed the State of Connecticut's determination
on the  coastal  zone  management  issue  to the  United  States  Department  of
Commerce.  On May 6, 2004,  the  Department of Commerce  overrode  Connecticut's
denial and granted the coastal zone  management  authorization.  Islander East's
petition  for a  declaratory  order  challenging  the denial of the  Section 401


                                       16
<PAGE>


authorization  is pending  with  Connecticut's  State  Superior  Court.  Once in
service,  the  pipeline is expected to  transport up to 285,000 DTH daily to the
Long Island and New York City energy markets, enough natural gas to heat 600,000
homes. The pipeline will also allow KeySpan to diversify the geographic  sources
of  its  gas  supply.  Various  options  for  the  financing  of  this  pipeline
construction are currently being evaluated.  As of December 31, 2004,  KeySpan's
total  capitalized  costs  associated  with the  siting  and  permitting  of the
Islander East pipeline were approximately $20 million.

In August  2004,  KeySpan  acquired a 21%  interest in the  Millennium  Pipeline
development project is anticipated to transport up to 500,000 DTH of natural gas
a day from Corning to Ramapo,  New York,  where it will connect to the Algonquin
pipeline. The other partners in the Millennium Pipeline are DTE Energy, Columbia
Gas Transmission  Corp., a unit of NiSource  Incorporated.  The project has been
approved  by  the  FERC  and,   pending  an  amendment  to  the  project's  FERC
certificate,  construction  could  begin as early as the third  quarter of 2005,
with service  beginning as early as November 2006. The Millennium  Pipeline will
provide  KeySpan  with new,  competitively  priced  supplies of natural gas from
Canada.  Further,  the project will increase  KeySpan's access to gas storage in
the Great Lakes region,  adding  critical  flexibility  to KeySpan's gas supply,
while  helping to control price  volatility  based on weather  conditions.  Once
constructed,  KeySpan plans to purchase  150,000 DTH per day from the Millennium
Pipeline  system,  which  represents  approximately  12.5%  of New  York  City's
peak-day  requirements.  As  of  December  31,  2004,  total  capitalized  costs
associated with the Millennium Pipeline project were $6 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 ("KLNG"),  is regulated by FERC.  In a joint
initiative  with BG LNG Services,  KeySpan plans to upgrade the KLNG facility to
accept  marine  deliveries  and  to  triple   vaporization  (or  regasification)
capacity.

On  February  25,  2005,  KLNG filed a lawsuit in federal  court to clarify  the
appropriate process to be used by the Rhode Island Coastal Resources  Management
Council  for its  review  of the  proposed  upgrade  of  KLNG's  energy  storage
facility.  Pending regulatory approvals,  the facility should be ready to accept
marine deliveries in the 2006 or 2007 timeframe.

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.


                                       17
<PAGE>


Natural Gas Distribution and Pipeline Activities in the United Kingdom

In December, 2003, the Company sold its interest in Phoenix Natural Gas Limited,
the gas  distribution  system  serving  the City of Belfast,  Northern  Ireland.
KeySpan  continues  to  own a  50%  interest  in  Premier  Transmission  Limited
("Premier"),  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.  In January of 2005,  KeySpan  decided to
proceed with the disposition of our 50% ownership  interest in Premier.  In view
of the likely disposition on the terms currently  contemplated,  a determination
was also made that a material  reduction in the carrying value of our investment
in this entity was required.  Accordingly,  in the fourth  quarter of 2004,  the
Company recorded a pre-tax impairment charge of $26.5 million for its investment
in Premier.

On February  25,  2005,  subsidiaries  of KeySpan  entered into a Share Sale and
Purchase  Agreement  with BG Energy  Holdings  Limited and Premier  Transmission
Financing  plc  ("PTF"),  pursuant  to which  all of the  outstanding  shares of
Premier are to be  purchased  by PTF.  It is  expected  that the sale of our 50%
interest in Premier  will result in net proceeds  before taxes of  approximately
$42.5 million. It is anticipated that the closing of this transaction will occur
before the end of the second quarter.

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
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.


                                       18
<PAGE>


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  facilities  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 were to expire in
2004.  To date,  five of the  permits  were  renewed and the  remaining  renewal
applications,  although in various stages of the regulatory process,  are deemed
completed by DEC. In addition,  three permit  modifications  were also submitted
and approved.  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 low NOX 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 emission  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 to enhance compliance options.

In 2003, New York State promulgated regulations which establish separate NOX and
SO2 emission  reduction  requirements on electric  generating  facilities in New
York  State  beginning  in late  2004  for  NOX  emissions  and in 2005  for SO2
emissions. KeySpan's facilities are expected to comply with the NOX requirements
without material additional capital expenditures because of previously installed
emissions  control  equipment and gas combustion  capability.  SO2 compliance is
expected  to require a reduction  in the sulfur  content of the fuel oil used in
our Northport and Port Jefferson facilities.

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.

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 ("CO2")) 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 additional natural gas firing
capability  have resulted in  approximately  a 15%  reduction in carbon  dioxide


                                       19
<PAGE>


emissions  since  1990,  while  the  electric  generation  industry  as a  whole
increased  carbon  dioxide  emissions  by more than  25%.  The  addition  of the
efficient,  combined cycle unit which began operation at Ravenswood in 2004 will
further reduce average KeySpan CO2 emission rates.

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 will likely be required by
the DEC. We are currently conducting studies as directed by the DEC to determine
the impacts of our discharges on aquatic  resources.  It is not possible at this
time to predict the extent of such  capital  investments  since they will depend
upon the outcome of the ongoing studies and the subsequent  determination by the
DEC to apply the standards set forth in recently promulgated federal regulations
under Section 316 of the Clean Water Act designed to mitigate such impacts.

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."

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."


                                       20
<PAGE>


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 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.

State Utility  Commissions.  Our regulated gas distribution 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 subsidiary which engages in the retail
sale of electricity is subject to certain  regulations of 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


                                       21
<PAGE>


for the Long Island generating  facilities with agreed-upon yearly  adjustments,
which have been approved by FERC.  These FERC approved rates expired on December
31,  2003. A rate filing  reflecting  a  recalculated  revenue  requirement  was
submitted  to FERC on October  31,  2003.  On  October  1, 2004 FERC  approved a
settlement  reached  between  KeySpan  and LIPA  with  respect  to new rates and
certain  other costs and  expenses.  Pursuant to the FERC  approved  settlement,
KeySpan  rates reflect a cost of equity of 9.5% with no revenue  increase.  FERC
also approved  updated  operating and  maintenance  expense levels and KeySpan's
recovery of certain other costs as agreed to by the parties.

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.

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.


                                       22
<PAGE>


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 and LIPA, at cost fairly and equitably allocated among them.

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
     a customer service  performance  program. At the end of KEDNY's and KEDLI's
     rate years (September 30, 2004 and November 30, 2004, respectively),  their
     ratios of debt to total utility capitalization were well in compliance with
     the ratios set forth  above and we have  incurred  no  penalties  under the
     outstanding customer service performance program.

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.

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


                                       23
<PAGE>


     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.

     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 FERC. The pricing for both energy sales and services to the
     NYISO  energy  market  is  still  evolving  and  some of the  FERC's  price
     mitigation measures are subject to rehearing and possible judicial review.

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

     To 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.


                                       24
<PAGE>


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

     Our  investments in natural gas and oil consist of our ownership of KeySpan
     Exploration and Production and  Seneca-Upshur.  We use the full cost method
     for KeySpan  Exploration and Production and  Seneca-Upshur.  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  fluctuate  substantially  on  a
     seasonal  basis.  In  addition,  our  New  England-based  gas  distribution
     subsidiaries  do not have weather  normalization  tariffs,  as we do in New
     York,  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.

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, our interest in
     KeySpan  Generation  LLC.  LIPA is in the process of performing a long-term
     strategic review initiative regarding its future direction.  It has engaged
     a team of advisors and  consultants  and is conducting  public  hearings to
     develop  recommendations to be submitted to the LIPA Trustees.  Some of the
     strategic  options that LIPA is considering  is whether it should  continue
     its  operations  as they  presently  exist,  fully  municipalize  or  fully
     privatize,  sell some,  but not all of its assets and become a regulator of
     rates and services, or merge with one or more utilities. Until LIPA makes a
     determination on its future direction,  we are unable to determine what the
     impact will be on our  financial  condition,  results of operations or cash
     flows.

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 Our Financial Condition


                                       25
<PAGE>


     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  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,  we are unable to  determine  what  effect,  if any,  the  ultimate
     resolution of these disputes will have on our financial condition,  results
     of operations, or cash flow.

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 segment
     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
     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.


                                       26
<PAGE>


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

     We recently  expanded the  Ravenswood  Facility,  our  merchant  generation
     plant, in our Electric  Services segment with the Ravenswood  Expansion,  a
     250 MW combined cycle generating unit. However, the Ravenswood Facility and
     Ravenswood  Expansion  continue  to be  subject to  competition  that could
     adversely impact the market price for the electricity they produce.  If new
     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  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, economic factors and price elasticity.
     In addition, our Gas Distribution segment's future growth 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 customer  conversions from an
     alternative  fuel to gas,  including  general  economic  factors  impacting
     customers' willingness to invest in new gas equipment.


                                       27
<PAGE>


Employee Matters

As  of  December  31,  2004,  KeySpan  and  its  wholly-owned  subsidiaries  had
approximately 10,000 employees. Of that total, approximately 5,800 employees 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.

Prior to their expiration in February 2004, 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
were 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 68, 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, Keyera
Energy Management Ltd. and J & W Seligman & Co.

Robert J. Fani

Mr.  Fani,  age 51, was elected to serve on the Board of Directors of KeySpan in
January  2005 and was  elected  its  President  and Chief  Operating  Officer in
October  2003.  Mr. Fani joined KEDNY in 1976,  and held a variety of management
positions  in  distribution,   engineering,  planning,  marketing  and  business
development.  After being  elected Vice  President  in 1992,  he was promoted to
Senior Vice  President of  Marketing  and Sales for KEDNY in 1997.  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.


                                       28
<PAGE>


Wallace P. Parker Jr.

Mr. Parker,  age 55, 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 January 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 for KEDNY and in August 1998 was promoted to
Senior Vice President of Human Resources of KeySpan.

Steven L. Zelkowitz

Mr.  Zelkowitz,  age 55, was elected  President of KeySpan's  Energy  Assets and
Supply  Group in  October  2003.  Prior to that,  he  served as  Executive  Vice
President and 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  and 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 J. Bishar, Jr.

Mr. Bishar, age 55, was elected Executive Vice President, General Counsel, Chief
Governance Officer and Secretary  effective March 1, 2005. He became Senior Vice
President,  General Counsel and Secretary in May 2003, with  responsibility  for
the Company's Legal Department and the Corporate  Secretary's  Office.  Prior to
that, he joined KeySpan as Senior Vice President and General Counsel in November
2002.  Before joining  KeySpan,  Mr. Bishar practiced law with Cullen and Dykman
LLP since 1987.  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.


                                       29
<PAGE>


John A. Caroselli

Mr.  Caroselli,  age 50, 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  Strategy and. 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  strategic  planning  brand
management, marketing,  communications,  human resources, facilities management,
e-business, change management and strategic execution.

Gerald Luterman

Mr. Luterman,  age 61, 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 IKON  Office  Solutions  Inc.,  and
Technology Solutions Company.

David J. Manning

Mr. Manning,  age 54, was elected Executive Vice President Corporate Affairs and
Chief  Environmental  Officer  effective  March 1, 2005.  He became  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 as Queens Council.

Anthony Nozzolillo

Mr.  Nozzolillo,  age 56, 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 51, 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 46, was elected President,  KeySpan Energy Delivery,  in
June,  2004 and Executive Vice President in April 2002. He previously  served as
President  of KeySpan  Energy New  England  since  April  2002,  and 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 a
director of Colonial Gas Company and currently  serves on the Board of Directors
for Enterprise Bank and Trust Company.

Joseph F. Bodanza

Mr. Bodanza,  age 57, was elected Senior Vice President  Regulatory  Affairs and
Asset  Optimization  effective  March 1, 2005. He became Senior Vice  President,
Regulatory Affairs and Chief Accounting Officer in April 2003. Prior to that, 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.

Coleen A. Ceriello

Ms.  Ceriello,  age 46, was named Senior Vice  President  of Shared  Services of
KeySpan Corporate Services, LLC, effective March 1, 2005. She had been KeySpan's
Vice President - Property,  Security and Employee Related Services since January
2005.  Prior to that time, she served as Vice President of Property and Security
since June 2004 and Vice President of Strategic  Planning since August 1999. She
joined  KEDNY in 1980 and over the  years  held a  succession  of  positions  in
Corporate Planning,  Regulatory Relations,  Information Technology and Strategic
Planning and Performance.


                                       31
<PAGE>


John F. Haran


Mr. Haran,  age 54, 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 April 2002.  Mr.  Haran joined KEDNY 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.

Michael J. Taunton

Mr. Taunton, age 49, was elected Senior Vice President, Treasurer and Chief Risk
Officer  effective  March 1, 2005. He became Senior Vice President and Treasurer
in March 2004, and 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.

Elaine Weinstein

Ms.  Weinstein,  age 58, was named Senior Vice President for Human Resources and
Chief  Diversity  Officer in March 2004.  She  previously  served as Senior Vice
President of KeySpan's Human Resources division since November 2000, and as Vice
President of Staffing and Organizational Development from September 1998, to her
election as Senior Vice President. Prior to that time, Ms. Weinstein was General
Manager of Employee  Development  since joining KEDNY in June of 1995.  Prior to
1995,  Ms.   Weinstein  was  Vice  President  of  Training  and   Organizational
Development at Merrill Lynch.

Lawrence S. Dryer

Mr. Dryer,  45, 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 A. Balog

Ms.  Balog,  age 43, was elected Vice  President  and Chief  Accounting  Officer
effective  March 1, 2005. She became 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.


                                       32
<PAGE>


Joseph E. Hajjar

Mr. Hajjar,  age 52, was named Vice President and Controller  effective March 1,
2005. He had been Senior Vice President and Chief  Financial  Officer of KeySpan
Services,  Inc.  since June 2003 and Senior Vice  President and Chief  Financial
Officer of KeySpan Business Solutions,  LLC, since November 2001. Before joining
KeySpan from 1998 to 2001,  Mr.  Hajjar was Executive  Vice  President and Chief
Operating Officer of Opportunity  America.  He also was previously an officer of
the Bovis group and served for over 12 years with Price Waterhouse.

Michael A. Walker

Mr.  Walker,  age 48, was named Vice  President  and Deputy  General  Counsel of
KeySpan Corporation,  effective March 1, 2005. He had been Senior Vice President
of KeySpan  Services,  Inc. since June 2004 and Senior Vice President and COO of
KeySpan  Business  Solutions,  LLC,  since June 2003.  Prior to that time he was
Senior Vice President and General Counsel of KeySpan Services, Inc. from January
2001 to December 2003.  Before joining KeySpan,  Mr. Walker was a shareholder in
the Corporate  Finance Section in the law firm of Buchanan  Ingersoll.  Prior to
joining  Buchanan  Ingersoll  he worked for  several law firms in the north east
representing both private and public sector clients on a wide variety of energy,
utility, regulatory, corporate and structured finance matters.


Item 2. Properties

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

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, 2004.









                                       33
<PAGE>

                                     PART II


Item 5. Market for Registrant's  Common Equity,  Related Stockholder Matters and
        Issuer Purchases of Equity Securities

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 February  15, 2005,
there were  approximately  72,549  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>
   2004                                High                    Low                     Dividends Per Share
   -------------------------------------------------------------------------------------------------------
  <S>                                  <C>                     <C>                     <C>
   First Quarter                       $38.60                  $35.72                  $0.445
   Second Quarter                      $38.99                  $33.87                  $0.445
   Third Quarter                       $39.50                  $35.19                  $0.445
   Fourth Quarter                      $41.53                  $37.57                  $0.445

   2003                                High                    Low                     Dividends Per Share
   -------------------------------------------------------------------------------------------------------

   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
</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, 2004:

<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                         10,540,946                            $33.15                             5,245,064
      Restricted Stock                          80,409                              N/A
      Performance Shares                       346,470                              N/A
Equity compensation plans
not approved by                                      0                                0                                      0
security holders
Total                                       10,967,825(1)                         $33.15                              5,245,064
</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.












                                       35
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------

Item 6 Selected Financial Data

                                                                                Year Ended December 31,
(In Thousands of Dollars, Except Per                    2004             2003            2002                2001              2000
  Share Amounts)                              -------------------------------------------------------------------------------------
<S>                                                 <C>              <C>             <C>                <C>             <C>
Income Summary
Revenues
     Gas Distribution                              $ 4,407,292      $ 4,161,272     $ 3,163,761        $ 3,613,551      $ 2,555,785
     Electric Services                               1,738,660        1,605,973       1,645,688          1,850,381        1,702,908
     Energy Services                                   182,406          158,908         208,624            243,553          245,775
     Energy Investments                                322,108          609,371         447,101            498,318          310,096
                                              --------------------------------------------------------------------------------------
Total revenues                                       6,650,466        6,535,524       5,465,174          6,205,803        4,814,564
                                              --------------------------------------------------------------------------------------
Operating expenses
     Purchased gas for resale                        2,664,492        2,495,102       1,653,273          2,171,113        1,408,680
     Fuel and purchased power                          540,302          414,633         395,860            538,532          460,841
     Operations and maintenance                      1,567,022        1,622,592       1,631,297          1,704,370        1,418,164
     Depreciation, depletion and amortization          551,760          571,669         513,708            564,039          326,748
     Early retirement and severance charges                  -                -               -                  -           65,175
     Operating taxes                                   404,212          418,236         380,527            448,914          421,936
     Impairment Charges                                 40,965                -               -                  -                -
                                              --------------------------------------------------------------------------------------
Total operating expenses                             5,768,752        5,522,232       4,574,665          5,426,968        4,101,544
                                              --------------------------------------------------------------------------------------
Gain on sale of property                                 7,021           15,123           4,730                  -                -
Income from equity investments                          46,536           19,214          14,096             13,129           20,010
                                              --------------------------------------------------------------------------------------
Operating income                                       935,270        1,047,629         909,335            791,964          733,030
Other income (deductions)                                4,983         (340,279)       (301,368)          (359,525)        (233,322)
Income taxes                                           325,540          281,281         229,665            200,472          208,549
                                              --------------------------------------------------------------------------------------
Earnings from continuing operations                    614,713          426,069         378,302            231,967          291,159
                                              --------------------------------------------------------------------------------------
Discontinued Operations
    Income (loss) from operations, net of tax          (78,960)          (1,888)         15,692             22,643            9,648
    Loss on disposal, net of tax                       (72,088)               -         (16,306)           (30,356)               -
                                              --------------------------------------------------------------------------------------
Loss from discontinued operations                     (151,048)          (1,888)           (614)            (7,713)           9,648
Cumulative change in accounting principles                   -          (37,451)              -                  -                -
                                              --------------------------------------------------------------------------------------
Net income                                             463,665          386,730         377,688            224,254          300,807
Preferred stock dividend requirements                    5,612            5,844           5,753              5,904           18,113
                                              --------------------------------------------------------------------------------------
Earnings for common stock                          $   458,053      $   380,886     $   371,935        $   218,350      $   282,694
                                              ======================================================================================
Financial Summary
Earnings per share ($)                                    2.86             2.41            2.63               1.58             2.10
Cash dividends declared per share ($)                     1.78             1.78            1.78               1.78             1.78
Book value per share, year-end ($)                       24.22            22.99           20.67              20.73            20.65
Market value per share, year-end ($)                     39.45            36.80           35.24              34.65            42.38
Shareholders, year-end                                  72,549           75,067          78,281             82,300           86,900
Capital expenditures ($)                               750,329        1,009,393       1,057,507          1,059,759          925,257
Total assets ($)                                    13,364,130       14,640,182      12,980,050         11,789,606       11,307,465
Common shareholders' equity ($)                      3,894,710        3,670,656       2,944,592          2,890,602        2,815,816
Preferred stock redemption required ($)                 75,000           75,000          75,000             75,000           75,000
Preferred stock no redemption required ($)                   -            8,568           8,849              9,077            9,205
Long-term debt ($)                                   4,418,729        5,610,948       5,224,081          4,697,649        4,116,441
Total capitalization ($)                             8,333,139        9,365,172       8,252,522          7,672,328        7,016,462
------------------------------------------------------------------------------------------------------------------------------------
</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  2.6  million  customers  in New York City,  Long
Island,  Massachusetts  and New Hampshire,  making KeySpan the fifth largest gas
distribution  company in the United States and the largest in the Northeast.  We
also own and operate electric  generating  plants in Nassau and Suffolk Counties
on Long  Island  and in  Queens  County  in New York  City  and are the  largest
electric generation operator in New York State. Under contractual  arrangements,
we provide power, electric transmission and distribution  services,  billing and
other customer services for approximately 1.1 million electric  customers of the
Long Island Power Authority ("LIPA").  KeySpan's other subsidiaries are involved
in gas exploration and production;  underground gas storage;  liquefied  natural
gas  storage;   retail  electric  marketing;   large  energy-system   ownership,
installation and management;  appliance service;  and engineering and consulting
services.  We also  invest and  participate  in the  development  of natural gas
pipelines, electric generation and other energy-related projects. (See Note 2 to
the  Consolidated   Financial  Statements  "Business  Segments"  for  additional
information on each operating segment.)

Executive Summary

Below is a table comparing the more  significant  items impacting  earnings from
continuing  operations  and earnings  available for common stock for the periods
indicated.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars, Except per Share Amounts)
                                                                           Year Ended December 31,

                                                        2004                             2003                         2002
                                           ---------------------------    ---------------------------    ---------------------------
                                               Earnings         E.P.S.         Earnings         E.P.S.        Earnings        E.P.S.
<S>                                           <C>              <C>             <C>            <C>            <C>             <C>
Earnings from continuing operations, less
           preferred stock dividends          $ 609,101        $ 3.80         $ 420,225       $ 2.65         $ 372,549       $ 2.64
Discontinued operations                        (151,048)        (0.94)           (1,888)       (0.01)             (614)       (0.01)
Cummulative change in accounting principle            -             -           (37,451)       (0.23)                -            -

                                           ---------------------------    ---------------------------    ---------------------------
Earnings for Common Stock                     $ 458,053        $ 2.86         $ 380,886       $ 2.41         $ 371,935       $ 2.63
                                           ===========================    ===========================    ===========================
Average shares outstanding                      160,294                         158,256                        141,263

Components of Continuing Operations:
-------------------------------------

Core operations                               $ 385,425        $ 2.41           353,191       $ 2.23           324,305       $ 2.30
Asset sales                                     257,506          1.60               995            -                 -            -
Ceiling test write-down                         (31,074)        (0.19)                -            -                 -            -
Impairment charges                              (31,318)        (0.20)                -            -                 -            -
Debt redemption costs                           (29,264)        (0.18)          (13,565)       (0.08)                -            -
Exploration and production operations            57,826          0.36            79,604         0.50            48,242         0.34

Earnings from continuing operations, less
          preferred stock dividends        ---------------------------    ---------------------------    ---------------------------
                                              $ 609,101        $ 3.80         $ 420,225       $ 2.65         $ 372,547       $ 2.64
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       37
<PAGE>


Earnings from Continuing Operations 2004 vs 2003

KeySpan's earnings from continuing  operations,  less preferred stock dividends,
for the year ended December 31, 2004 were $609.1 million or $3.80 per share,  an
increase of $188.9 million,  or $1.15 per share compared to $420.2  million,  or
$2.65 per share  realized in 2003.  Earnings from  continuing  operations,  less
preferred  stock  dividends,  for the year ended  December  31, 2002 were $372.5
million,  or $2.64 per share.  KeySpan's  financial  results  for the year ended
December 31, 2004 and 2003 reflect the  following  items that had a  significant
impact on  comparative  results:  (i) non-core asset sales recorded in both 2004
and 2003;  (ii) impairment  charges  recorded in 2004; and (iii) debt redemption
charges recorded in both 2004 and 2003.

During  2004,  KeySpan  sold its  interest  in The Houston  Exploration  Company
("Houston  Exploration")  - an independent  natural gas and oil  exploration and
production  company  located in Houston,  Texas.  We received  cash  proceeds of
approximately  $758 million in two stock  transactions  and  recorded  after-tax
gains of $222.7  million,  or $1.39 per share.  Also in 2004,  KeySpan  sold its
remaining  ownership  interest  in  KeySpan  Canada  -  previously  a 61%  owned
subsidiary  with  natural gas  processing  plants and  gathering  facilities  in
Western Canada.  We received cash proceeds of approximately  $255 million in two
transactions and recorded after-tax gains of $34.8 million,  or $0.21 per share.
Combined,  these asset sales provided  KeySpan with  approximately $1 billion of
cash proceeds and after-tax earnings of $257.5 million, or $1.60 per share.

As mentioned,  during 2003 KeySpan  completed two non-core asset sales. In 2003,
KeySpan sold 39.09% of its interest in KeySpan Canada. Additionally, we sold our
20% interest in Taylor NGL LP that owns and operates two extraction  plants also
located in Canada. We recorded an after-tax loss of $34.1 million,  or $0.22 per
share,  associated  with these  sales.  Additionally,  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,  or $0.12 per share,  on
this  transaction.  Income taxes were not provided on this transaction since the
transaction  was  structured  as a return of  capital.  Further,  in the  fourth
quarter of 2003, we completed the sale of our 24.5% interest in Phoenix  Natural
Gas, a natural  gas  distribution  company  located  in  Northern  Ireland,  and
recorded  an  after-tax  gain of $16.0  million,  or $0.10 per share.  In total,
KeySpan  recorded a pre-tax gain of $13.4 million from the monetization of these
non-core assets.  The combined after-tax gain from these asset sales was minimal
due to the tax treatment associated with each transaction.

See Note 2 to the Consolidated  Financial Statements "Business Segments" and the
discussions under the caption "Review of Operating Segments" for a more detailed
discussion of each of the above noted non-core stock transactions.

KeySpan recorded three  significant  impairment  charges during 2004 (a goodwill
impairment charge recorded in the Energy Services segment,  as well as a ceiling
test  write-down and carrying  value  impairment  charge  recorded in the Energy
Investment segment) that resulted in after-tax charges to continuing  operations
of $62.4 million,  or 0.39 per share.  The Energy Services  segment  recorded an
after-tax  non-cash goodwill  impairment  charge of $12.6 million,  or $0.08 per
share in  continuing  operations  as a result of an  evaluation  of the carrying
value of goodwill  recorded in this segment.  Based upon the  operating  results
experienced by the Energy Services segment and management's opinion that it was



                                       38
<PAGE>


likely that a significant  portion of the Energy Services  segment would be sold
within one year,  KeySpan  conducted an evaluation of the carrying  value of its
investments  in this  segment,  including  recorded  goodwill.  That  evaluation
resulted in a total impairment  charge of $152.4 million after tax, or $0.95 per
share - $12.6 million of this charge is attributable  to continuing  operations,
while the remaining  $139.9 million,  or $0.87 per share,  has been reflected in
discontinued  operations.  (See Note 11 to the Consolidated Financial Statements
"Energy  Services -  Discontinued  Operations"  for  additional  details on this
charge.)

KeySpan's  wholly-owned gas exploration and production  subsidiaries recorded an
after-tax  non-cash  impairment charge of $31.1 million,  or $0.19 per share, to
recognize  the  reduced  valuation  of  proved  reserves.  (See  Note  10 to the
Consolidated  Financial  Statements "Gas  Exploration and Production  Property -
Depletion" for additional details on this transaction.)

In addition to the asset sales  noted  previously,  KeySpan has entered  into an
agreement to sell its 50% interest in Premier  Transmission  Limited ("PTL"),  a
gas pipeline from southwest Scotland to Northern Ireland,  before the end of the
second quarter of 2005. In the fourth quarter of 2004 KeySpan recorded a pre-tax
non-cash  impairment  charge of $26.5 million - $18.8 million after-tax or $0.12
per share,  reflecting the difference between the anticipated cash proceeds from
the sale of PTL compared to its carrying value. This investment is accounted for
under the equity method of accounting in the Energy  Investments  segment.  (See
Note 2 to the  Consolidated  Financial  Statements  "Business  Segments" and the
discussions under the caption "Review of Operating Segments" for a more detailed
discussion of the anticipated sale.

The remaining  significant item noted above is debt redemption costs incurred in
2004  and  2003.  In  2004,  KeySpan  redeemed  approximately  $758  million  of
outstanding  long-term  debt.  KeySpan  incurred  $54.5 million in call premiums
associated  with this  redemption,  of which $45.9 was  expensed and recorded in
other  income and  deductions  on the  Consolidated  Statement  of  Income.  The
remaining  amount of the call premiums  have been deferred for future  recovery.
Further,  KeySpan wrote-off $8.2 million of previously  deferred financing costs
which have been reflected in interest expense on the  Consolidated  Statement of
Income.  The total after-tax expense of the debt redemption was $29.3 million or
$0.18 per share. (See Note 6 to the Consolidated Financial Statements "Long-Term
Debt  and  Commercial  Paper"  as  well  as the  discussion  under  the  caption
"Financing"  for  additional  details  on this  transaction.)  In 2003,  KeySpan
incurred $18.2 million in debt redemption  costs  associated with the redemption
of approximately  $447 million of outstanding  promissory notes that were issued
to the Long Island Power Authority  ("LIPA") in connection with the KeySpan/Long
Island Lighting Company ("LILCO")  business  combination  completed in May 1998.
Further,  Houston  Exploration,  then a consolidated  subsidiary,  incurred debt
redemption costs of $5.9 million, to retire $100 million 8.625% Notes. The total
after-tax expense of the debt redemptions in 2003 was $13.6 million or $0.08 per
share.

The net impact of the above  mentioned items resulted in an increase to earnings
from continuing  operations of $165.9  million,  or $1.03 per share for the year
ended December 31, 2004,  compared to a loss of $12.6 million or $0.08 per share
in 2003.

The remaining items impacting  comparative  earnings from continuing  operations
reflect higher earnings from the Gas  Distribution  segment,  primarily due to a
Boston Gas Company rate increase  resulting from a rate proceeding  concluded in
November 2003, partially offset by the adverse effect on earnings from KeySpan's
lower ownership level in Houston  Exploration.  As mentioned above and discussed


                                       39
<PAGE>


in more  detail in Note 2 to the  Consolidated  Financial  Statements  "Business
Segments,"  during the first half of 2004 KeySpan  maintained an approximate 55%
ownership  level in  Houston  Exploration.  In June  2004,  KeySpan's  ownership
decreased to  approximately  23.5% and then in November 2004 KeySpan  decided to
sell its remaining investment.

Earnings Available for Common Stock 2004 vs 2003

Earnings  available  for common stock for the year ended  December 31, 2004 also
includes losses from  discontinued  operations.  As noted, at December 31, 2004,
KeySpan  intended to sell a  significant  portion of its  ownership  interest in
certain  companies  within  the Energy  Services  segment -  specifically  those
companies engaged in mechanical  contracting  activities.  As a result,  KeySpan
recorded  a loss in  discontinued  operations  of $151.1  million,  or $0.94 per
share.  This loss reflects the $139.9 million  after-tax  impairment  charges to
reflect a reduction to the carrying value of assets  associated  with mechanical
contracting  activities and operating  losses of $11.2 million.  (See Note 11 to
the Consolidated Financial Statements "Energy Services-Discontinued  Operations"
for additional details on these items.)

Earnings  available  for common stock for the year ended  December 31, 2003 have
been reclassified to reflect an operating loss from  discontinued  operations of
$1.9  million,  or  $0.01  per  share  associated  with  the  operations  of the
mechanical  contracting  activities.  Earnings  available  for common stock also
include a charge for a cumulative  change in  accounting  principle.  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." This Interpretation  required us to,
among other things,  consolidate  the  Ravenswood  Master Lease (the lease under
which  KeySpan  leases  and  operates  a  portion  of  the  Ravenswood  electric
generating facility ("Ravenswood Facility") and classify the lease obligation as
long-term debt on the Consolidated  Balance Sheet starting 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.)

Earnings from Continuing Operations 2003 vs 2002

Income from continuing  operations,  less preferred stock  dividends,  increased
$47.7 million in 2003 compared to 2002 primarily reflecting higher earnings from
the Energy  Investments and Gas  Distribution  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 of 2002,  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.  Earnings per share from continuing  operations
increased  only $0.01 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.


                                       40
<PAGE>


Earnings Available for Common Stock 2003 vs 2002

As mentioned,  earnings  available for common stock for the year ended  December
31,  2003,  reflects an  operating  loss from  discontinued  operations  of $1.9
million,  or $0.01 per share  associated  with the  operations of the mechanical
contracting  activities,  as well  as a  non-cash,  after-tax  charge  of  $37.6
million, or $0.23 per share related to the implementation of FIN 46.

Earnings  available  for  common  stock for the year  ended  December  31,  2002
includes  a net loss of $0.6  million,  or $0.01 per  share,  from  discontinued
operations.  The mechanical  contracting  operations reflected earnings of $19.1
million,  or $0.13 per share in discontinued  operations.  This was offset by an
after-tax loss of $19.7 million associated with the sale of Midland  Enterprises
LLC ("Midland").  In January 2002, KeySpan announced that it had entered into an
agreement to sell 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.  (See Note 9 to the Consolidated  Financial  Statements  "Discontinued
Midland Operations" for additional information.)






                                       41
<PAGE>


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)                              2004              2003              2002
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>              <C>                <C>
 Gas Distribution                                                              $ 579,563        $  574,254         $ 531,134
 Electric Services                                                               289,781           269,874           289,694
 Energy Services
      Operations                                                                 (33,878)          (32,963)          (45,581)
      Goodwill impairment charge                                                 (14,424)                -                 -
 Energy Investments
      Operations                                                                 179,424           238,554           142,594
      Ceiling test write-down and impairment charge                              (74,731)                -                 -
 Eliminations and other                                                            9,535            (2,090)           (8,506)
                                                                      -------------------------------------------------------
 Operating Income                                                                935,270         1,047,629           909,335
 Interest charges                                                               (331,251)         (307,694)         (301,504)
 Gain on Houston Exploration transactions                                        329,689            19,020                 -
 Gain (loss) on sale of KeySpan Canada                                            58,629           (30,345)                -
 Gain on sale of Phoenix Natural Gas                                                   -            24,681                 -
 Cost of debt redemption                                                         (45,879)          (24,094)                -
 Other income and (deductions)                                                    (6,205)          (21,847)              136
 Income taxes                                                                   (325,540)         (281,281)         (229,665)
                                                                      -------------------------------------------------------
 Income from Continuing Operations                                               614,713           426,069           378,302
 Cumulative change in accounting principles                                            -           (37,451)                -
 Loss from discontinued operations                                              (151,048)           (1,888)             (614)
                                                                      -------------------------------------------------------
 Net Income                                                                      463,665           386,730           377,688
 Preferred stock dividend requirements                                             5,612             5,844             5,753
                                                                      -------------------------------------------------------
 Earnings for Common Stock                                                     $ 458,053        $  380,886         $ 371,935
                                                                      =======================================================

 Basic Earnings per Share:
    Continuing operations, less preferred stock dividends                      $    3.80        $     2.65         $    2.64
    Change in accounting principles                                                    -             (0.23)                -
    Discontinued operations                                                        (0.94)            (0.01)            (0.01)
-----------------------------------------------------------------------------------------------------------------------------
                                                                               $    2.86        $     2.41         $    2.63
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>

Operating income, as indicated in the above table,  decreased $112.4 million for
the twelve months ended December 31, 2004,  compared to the same period of 2003.
Comparative  operating  income was adversely  impacted by lower operating income
from the Energy  Investment  segment as a result of KeySpan's  reduced ownership
interest in Houston  Exploration  and KeySpan  Canada  during the latter half of
2004.  In  addition,  operating  income in the Energy  Investments  segment  was
adversely impacted by the $48.2 million non-cash  impairment charge to recognize
the reduced valuation of proved reserves,  as well as the $26.5 million non-cash
impairment charge in our investment in PTL.  Further,  the decrease in operating
income reflects the $14.4 million non-cash  goodwill  impairment charge recorded
in the Energy Services segment.  The higher comparative  operating income in the
Electric Services segment in 2004 primarily reflects higher net electric margins
associated with the Ravenswood Expansion, a recently constructed 250 MW combined
cycle  generating  facility  located at the  Ravenswood  Facility  site. The Gas
Distribution   segment   benefited   from  customer   additions  and  oil-to-gas
conversions throughout our service territories,  as well as from the full effect
of the rate  increase  resulting  from the Boston Gas  Company  rate  proceeding
concluded in November  2003.  As mentioned  earlier,  in 2003 we recorded  $15.1
million in gains  from  property  sales,  primarily  550 acres of real  property
located on Long Island, that were recorded in the Gas Distribution segment. (See
the  discussion  under the caption  "Review of Operating  Segments"  for further
details on each segment.)


                                       42
<PAGE>


The increase in interest expense of $23.6 million,  or 8%, in 2004,  compared to
the prior year,  reflects a number of items. As noted earlier,  interest expense
for 2004 includes the write-off of $8.2 million of previously  deferred issuance
costs as a result of the  redemption  of $758 million of  outstanding  long-term
debt. In addition,  interest expense in 2004 was impacted by the  implementation
of FIN  46,  mentioned  earlier.  Beginning  January  1,  2004,  lease  payments
associated  with the  Ravenswood  Master  Lease have been  reflected as interest
expense on the  Consolidated  Statement  of Income  resulting  in an increase to
interest expense of approximately  $30 million in 2004. (See Note 7 "Contractual
Obligations,  Financial  Guarantees and Contingencies for further information on
the Master Lease.")

Further,  comparative  interest  expense also reflects the benefits  realized in
2003  associated  with interest  rate swaps.  In 2003, we terminated an interest
rate swap agreement with a notional  amount of $270 million.  This swap was used
to hedge a portion of outstanding  promissory  notes that were issued to LIPA in
connection with the KeySpan/LILCO business combination.  As noted previously, in
March 2003, we called  approximately $447 million of the outstanding  promissory
notes, and settled the outstanding derivative instrument. The cash proceeds from
the  termination  of the interest rate hedge were $18.4  million,  of which $8.1
million   represented   accrued  swap  interest.   The  difference  between  the
termination  settlement  amount and the amount of accrued swap  interest,  $10.3
million, was recorded to earnings (as an adjustment to interest expense) in 2003
and effectively offset a portion of the redemption charges.

Offsetting,  to some  extent,  these  adverse  impacts to  comparative  interest
expense are the benefits associated with a lower level of outstanding  long-term
debt.

In addition to the asset sales of $388.3  million and debt  redemption  costs of
$45.9 million  previously noted, other income and (deductions) for 2004 reflects
a $12.6  million  gain  recorded on the  settlement  of a  derivative  financial
instrument  entered  into in  connection  with  the  sale/leaseback  transaction
associated  with the  Ravenswood  Expansion,  as well as a $5.5 million  foreign
currency gain on cash investments held off-shore.  Other income and (deductions)
also includes the effects of minority  interest of $36.8 million  related to our
previous  controlling  interests in Houston  Exploration and KeySpan Canada,  as
well as carrying charges on certain regulatory assets. (See Note 7 and Note 8 to
the  Consolidated  Financial  Statements,  "Contractual  Obligations,  Financial
Guarantees   and   Contingencies"   and   "Hedging  and   Derivative   Financial
Instruments,"   for   additional   information   regarding  the   sale/leaseback
transaction and derivative financial instrument.)

In  addition to the asset sales of $13.4  million and debt  redemption  costs of
$24.1  million  previously  noted,  other income and  (deductions)  in 2003 also
reflects  severance  tax  refunds  totaling  $21.6  million  recorded by Houston
Exploration  for severance  taxes paid in 2002 and earlier  periods,  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 of $63.9  million,  as well as carrying
charges on certain regulatory assets.


                                       43
<PAGE>


Income tax expense generally  reflects the level of pre-tax income. In addition,
tax expense for 2004  reflects:  (i) a $6.0  million  benefit  resulting  from a
revised appraisal  associated with property that was disposed of in 2003; (ii) a
tax  benefit  of $14  million  related  to the  repatriation  of  earnings  from
KeySpan's Canadian investments;  and (iii) the beneficial tax treatment afforded
the stock transaction with Houston Exploration.

Income tax expense  for 2003  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 Commonwealth 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.

As noted  earlier,  earnings  available  for  common  stock  for the year  ended
December 31, 2004 also includes  losses of $151.1  million,  or $0.94 per share,
from discontinued  operations.  Earnings available for common stock for the year
ended December 31, 2003 includes a charge for a cumulative  change in accounting
principles  of  $37.6  million,   or  $0.23  per  share,   associated  with  the
implementation of FIN 46, as well as operating losses of $1.9 million,  or $0.01
per share associated with discontinued operations.

As a result of the items discussed  above,  earnings  available for common stock
were $458.1  million,  or $2.86 per share for the year ended  December  31, 2004
compared to $380.9 million, or $2.41 per share realized in 2003.

Operating  income  in 2003  increased  $138.3  million  compared  to 2002.  This
increase  in  operating   income   reflects  higher  earnings  from  the  Energy
Investments  and Gas  Distribution  segments,  somewhat  offset by a decrease in
earnings  from the Electric  Services  Segment.  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
of 2002, as well as from load growth. Further, as mentioned earlier, during 2003
we recorded $15.1 million in gains in the Gas Distribution segment from property
sales.  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 in 2003.  (See the  discussion
under the caption  "Review of Operating  Segments"  for further  details on each
segment.)

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


                                       44
<PAGE>


As discussed in greater detail  earlier,  other income and  (deductions) in 2003
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  Houston  Exploration  and
recorded  a net  gain of  $13.4  million  associated  with  these  transactions.
Further,  we incurred debt redemption  costs of $24.1 million.  Other income and
(deductions) in 2003 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)  for both  2003 and 2002  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.  As mentioned above,
the partial  monetization  of our Canadian  investments  in 2003 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  Commonwealth  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 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.

As discussed  earlier,  earnings  available  for common stock for the year ended
December 31, 2002 also includes a net loss from discontinued  operations of $0.6
million.

As a result of the items just  mentioned  earnings  available  for common stock,
which includes both the cumulative  change in accounting  principle,  as well as
discontinued  operations,  were $380.9 million,  or $2.41 per share for the year
ended December 31, 2003 compared to $371.9 million, or $2.63 per share earned in
2002.


                                       45
<PAGE>


KeySpan's  consolidated  earnings for 2004 were 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) were forecasted to
be in the range of $2.20 to $2.30 per share.  Earnings from gas  exploration and
production  operations,  excluding the impact of the gain on the sale of Houston
Exploration and the impact of the non-cash impairment charge, were forecasted to
be in the  range  of $0.35  to  $0.45  per  share.  Actual  2004  earnings  from
continuing core  operations,  as defined,  were $2.41 per share,  while earnings
from exploration and production operations were $0.36 per share.

Financial Outlook for 2005

KeySpan's  consolidated  earnings for 2005 are  forecasted to be in the range of
$2.30 to $2.40 per share, excluding special items. Since we sold the majority of
our non-core assets in 2004, the earnings forecast  represents earnings from all
continuing  operations less preferred  stock  dividends.  Further,  the earnings
forecast  includes the  anticipated  dilutive  impact from the conversion of the
MEDS  Equity  Units.  (See  Note  6 to  the  Consolidated  Financial  Statements
"Long-Term Debt" for an explanation of the MEDS Equity Units.)

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

KeySpan's segment results are reported on an Operating Income basis.  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.


                                       46
<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)                                               2004                 2003                  2002
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>                  <C>                   <C>
Revenues                                                            $ 4,407,292          $ 4,161,272           $ 3,163,761
Cost of gas                                                           2,664,662            2,444,485             1,569,325
Revenue taxes                                                            73,294               90,456                83,066
---------------------------------------------------------------------------------------------------------------------------
Net Gas Revenues                                                      1,669,336            1,626,331             1,511,370
---------------------------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                                           672,548              659,932               608,266
   Depreciation and amortization                                        276,487              259,934               237,186
   Operating taxes                                                      140,738              147,334               135,687
---------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                              1,089,773            1,067,200               981,139
---------------------------------------------------------------------------------------------------------------------------
Gain on the sale of property                                                  -               15,123                   903
Operating Income                                                    $   579,563          $   574,254           $   531,134
---------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH)                                324,549              328,073               284,281
Transportation - Electric  Generation (MDTH)                             27,656               34,778                64,173
Other Sales (MDTH)                                                      155,992              158,722               209,002
Warmer (Colder) than Normal - New York & Long Island                      (1.0%)               (8.0%)                 7.0%
Warmer (Colder) than Normal - New England                                 (6.8%)              (10.0%)                 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.


Executive Summary

Operating income increased $5.3 million for the twelve months ended December 31,
2004 compared to the same period last year,  primarily due to an increase in net
revenues  of $43.0  million  resulting,  for the most part,  from the Boston Gas
Company's  rate  proceeding  that was  concluded  in  November  2003.  Partially
offsetting the increase in net revenues were higher operating  expenses of $22.6
million,  primarily  due to an increase of $13.0  million in the  provision  for
uncollectible  accounts  receivable as a result of higher gas costs,  as well as
higher  depreciation and amortization  expenses.  It should be noted that during
2003 we recorded $15.1 million in gains from property sales on Long Island.

Operating  income  increased  $43.1 million for the twelve months ended December
31, 2003  compared to the same period of 2002,  primarily  due to an increase in
net revenues of $115.0 million resulting from  significantly  colder than normal
weather   experienced   throughout  the  Northeastern  United  States  in  2003,
particularly  during the primary winter heating months of January through March.
Partially offsetting the increase in net revenues were higher operating expenses
of  $86.1  million,   attributable,   in  part,  to  higher  pension  and  other
postretirement  benefit  costs of $30.9  million.  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.  Also depreciation and amortization  expense increased as a
result of the expansion of the gas distribution system. As noted earlier, during
2003 we recorded $15.1 million in gains from property sales on Long Island.


                                       47
<PAGE>


Net Revenues

Net gas revenues  (revenues less the cost of gas and  associated  revenue taxes)
from our gas distribution  operations increased by $43.0 million, or 3%, for the
year-ended  December  31,  2004  compared to the prior  year.  Net gas  revenues
benefited  from the  Boston  Gas  Company  rate  increase  granted in the fourth
quarter of 2003, as well as from customer additions and oil-to-gas  conversions.
As  measured  in heating  degree  days,  weather in 2004 in our New York and New
England  service  territories  was  approximately  1% and 7% colder than normal,
respectively,  compared to  approximately 8% and 10% colder than normal in 2003,
respectively.  Weather in 2004 was  approximately 6% warmer than 2003 in our New
York service  territory  and  approximately  3% warmer than last year in our New
England service territory.

Net revenues from firm gas customers  (residential,  commercial  and  industrial
customers)  in our New York  service  territory  during the twelve  months ended
December 31, 2004 were  essentially  equivalent  to the same period of 2003.  We
realized a $3.5 million benefit to net gas revenues as a result of an additional
billing day in the 2004 leap year and $1.6 million  associated  with  regulatory
incentives.  Weather,  which was warmer than 2003, resulted in an adverse impact
to  comparative  net gas revenues of $3.6 million.  KEDNY and KEDLI each operate
under a utility  tariff that contains a weather  normalization  adjustment  that
significantly  offsets  variations in firm net revenues due to  fluctuations  in
normal  weather.  Since  weather  was colder  than  normal we  refunded  to firm
customers  $5.2  million  through  the  weather  normalization  adjustment.  The
benefits of customer  additions  and  oil-to-gas  conversions  were  effectively
offset by conservation and more efficient heating equipment,  customer attrition
and the adverse impact to customer usage due to higher natural gas prices.

Also  included in net gas revenues is the  recovery of property  taxes that were
$0.5 million lower in 2004 compared to 2003.  These  revenues,  however,  do not
impact net income  since the taxes they are  designed to recover are expensed as
amortization  charges  on  the  Consolidated   Statement  of  Income.  Firm  gas
distribution  rates for KEDNY and KEDLI during 2004, other than for the recovery
of gas costs, have remained substantially unchanged from rates charged in 2003.

Net  revenues  from firm gas  customers  in our New  England  service  territory
increased by $40.3  million in 2004  compared to 2003.  Customer  additions  and
oil-to-gas conversions, net of attrition and conservation, added $8.0 million to
net gas  revenues.  Further,  we  realized  a $2.2  million  benefit  in net gas
revenues as a result of an  additional  billing day for leap year. As mentioned,
the Massachusetts Department of Telecommunications and Energy ("MADTE") approved
a $27  million  base rate  increase  for the Boston Gas  Company,  which  became
effective  November 1, 2003.  For the twelve months ended December 31, 2004, the
rate increase  resulted in a benefit to net gas revenues of $29.4 million.  (See
the  caption  under  "Regulation  and  Rate  Matters"  for  further  information
regarding the rate filing.) The gas  distribution  operations of our New England
based  subsidiaries  do not have a weather  normalization  adjustment.  Weather,
which was warmer in 2004 than 2003, resulted in an adverse impact to comparative
net gas  revenues of $6.1  million.  To mitigate the effect of  fluctuations  in
normal weather patterns on KEDNE's results of operations and cash flows, weather
derivatives  were in place for the 2003/2004 and the  2004/2005  winter  heating
seasons.  The impact of these  derivative  instruments  resulted  in a favorable
impact to  comparative  net revenues of $6.8 million for the twelve months ended
December  31,  2004  compared  to the same  period  in 2003.  (See Note 8 to the
Consolidated Financial Statements "Hedging and Derivative Financial Instruments"
for further information.)


                                       48
<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. These "dual-fuel"  customers
can consume either natural gas or fuel oil for heating purposes. Net revenues in
these markets  increased  $2.2 million in 2004 compared to 2003. The majority of
interruptible  profits  earned by KEDNE and KEDLI are returned to firm customers
as an offset to gas costs.

Net gas  revenues  from our gas  distribution  operations  increased  by  $115.0
million,  or 8%, for the year ended  December  31,  2003,  compared  to the same
period  in  2002.  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  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 of 2002.  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  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 of 2002. 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


                                       49
<PAGE>


utilities of  approximately  $25.1  million in 2003  compared to 2002.  As noted
above, 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
in 2002. 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.

In our large-volume  heating and other  interruptible  (non-firm)  markets,  net
revenues  increased by $26.8 million during the twelve months ended December 31,
2003,  compared  to the same  period of 2002.  As  mentioned,  the  majority  of
interruptible  profits  earned by KEDNE and KEDLI are returned to firm customers
as an offset to gas costs.

We are committed to our expansion  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
37% of the residential and multi-family  markets,  and  approximately 55% of the
commercial  market  currently  use natural gas for space  heating.  Further,  we
estimate that in our New England service  territories  approximately  50% of the
residential  and  multi-family  markets,  as  well  as  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.


                                       50
<PAGE>


Firm Sales, Transportation and Other Quantities

Firm gas sales and  transportation  quantities for the  year-ended  December 31,
2004,  were  approximately  1% lower  compared to such  quantities  for the same
period  in  2003  reflecting  the  warmer  weather.   Weather  normalized  sales
quantities  increased 2% in our New York service territories during 2004. In our
New England service territories, weather normalized sales quantities during 2004
were essentially the same as weather normalized sales quantities  experienced in
2003.  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 full sales service
customers.  Transportation quantities related to electric generation reflect the
transportation  of gas to our  electric  generating  facilities  located on Long
Island. Net revenues from these services are not material.

Other sales quantities include on-system  interruptible  quantities,  off-system
sales quantities  (sales made to customers  outside of our service  territories)
and related  transportation.  We have an agreement  with Coral  Resources,  L.P.
("Coral"),  a subsidiary of Shell Oil Company,  under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI. Upon expiration of this agreement, March 31, 2005,
these  services  will be  performed  with  KeySpan  employees.  We  also  have a
portfolio  management  contract with Merrill Lynch Trading,  under which Merrill
Lynch Trading provides all of the city gate supply requirements at market prices
and  manages  certain  upstream  capacity,  underground  storage and term supply
contracts for KEDNE. This agreement expires on March 31, 2006.

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.

Purchased Gas for Resale

The  increase  in gas costs for the  twelve  months  ended  December  31,  2004,
compared  to the same  period  of 2003 of $220.2  million,  or 9%,  reflects  an
increase of 13% in the price per dekatherm of gas  purchased,  and a 3% decrease
in the quantity of gas purchased.  The current gas rate structure of each of our
gas distribution  utilities includes a gas adjustment clause,  pursuant to which
variations  between actual gas costs incurred for sale to firm customers and gas
costs billed to firm  customers  are deferred and refunded to or collected  from
customers in a subsequent  period.  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.


                                       51
<PAGE>


Operating Expenses

Total  operating  expenses for the year ended December 31, 2004 increased  $22.6
million,  or 2%,  compared  to the same  period  last  year,  reflecting  higher
operations and maintenance and depreciation expense.  Operations and maintenance
expense  increased $12.6 million,  or 2%, in 2004 compared to 2003 primarily due
to an increase of $13.0  million in the  provision  for  uncollectible  accounts
receivable  as a result of  increasing  gas  costs,  as well as higher  employee
welfare costs,  primarily  postretirement  expenses of approximately $4 million.
These increases to operations and maintenance  expenses were partially offset by
a benefit of  approximately  $3 million,  net of amounts  subject to  regulatory
deferral   treatment,   associated  with  the  implementation  of  the  Medicare
Prescription Drug Improvement and Modernization Act of 2003 ("Medicare Act") and
implementation  of Financial  Accounting  Standards Board Staff Position ("FSP")
106-2.  (See  Note  1 to  the  Consolidated  Financial  Statements  "Summary  of
Significant  Accounting Policies" Item O "Recent Accounting  Pronouncements" for
further information  regarding the Act and FSP 106-2.) In addition, in September
2004,  Boston Gas Company  reached an agreement  with an  insurance  carrier for
recovery of previously incurred environmental  expenditures.  Under a previously
issued MADTE order, insurance and third-party recoveries,  after deducting legal
fees, are shared  between Boston Gas and its firm gas customers.  As a result of
the  insurance  agreement,  in  September  2004 Boston Gas recorded a $5 million
benefit to operations and maintenance expense.

Higher depreciation and amortization expense reflects the continued expansion of
the gas distribution  system, while the lower operating taxes resulted primarily
from a property tax refund in our New York service territory.

Operating  expenses in 2003 increased  $86.1 million,  or 9%,  compared to 2002.
This  increase  was  primarily   attributable   to  higher   pension  and  other
postretirement  benefit  costs,  which  increased  (net of amounts  deferred and
subject to regulatory  true-ups) by $30.9 million during 2003. The cost of these
benefits grew 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.


                                       52
<PAGE>


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

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 Shoreham, Long Island.  Applications for all necessary
regulatory  authorizations  were  filed  in 2000  and  2001.  Islander  East has
received a final  certificate  from the  Federal  Energy  Regulatory  Commission
("FERC")  and all  necessary  permits  from the State of New York.  The State of
Connecticut denied Islander East's  applications for coastal zone management and
Section 401 of the Clean Water Act  authorizations.  Islander  East appealed the
State of Connecticut's determination on the coastal zone management issue to the
United States Department of Commerce. On May 6, 2004, the Department of Commerce
overrode   Connecticut's   denial  and  granted  the  coastal  zone   management
authorization.  Islander East's petition for a declaratory order challenging the
denial of the Section 401  authorization  is pending  with  Connecticut's  State
Superior  Court.  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.  Various  options for the
financing of this pipeline  construction  are being  evaluated.  At December 31,
2004, our investment in the Islander East pipeline was $20 million.

In addition,  in August 2004,  KeySpan acquired a 21% interest in the Millennium
Pipeline development project which is anticipated to transport up to 500,000 DTH
of natural gas a day to the Algonquin pipeline. The project has been approved by
the  FERC  and,  pending  an  amendment  to  the  project's  FERC   certificate,
construction  could begin as early as the third  quarter of 2005,  with  service
beginning in late 2006. Once constructed,  KeySpan  anticipates  contracting for
150,000 DTH per day of  transportation  capacity  from the  Millennium  Pipeline
system. As of December 31, 2004, our investment in this project was $6 million.

Electric Services

The Electric  Services segment  primarily  consists of subsidiaries that own and
operate oil and gas-fired  electric  generating  plants in the Borough of Queens
(including the "Ravenswood  Projects") and the counties of Nassau and Suffolk on
Long Island.  In addition,  through long-term  contracts of varying lengths,  we
manage the electric  transmission and distribution  ("T&D") system, the fuel and
electric  purchases,  and the  off-system  electric sales for LIPA. The Electric
Services  segment also provides  retail  marketing of  electricity to commercial
customers,  the  earnings  from which  were  previously  reported  in the Energy
Services segment.  Financial results for 2003 and 2002 have been reclassified to
reflect these activities in the Electric Services segment.


                                       53
<PAGE>


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)                                                   2004               2003              2002
------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>                <C>               <C>
Revenues                                                               $ 1,738,660        $ 1,606,074       $ 1,645,789
Purchased fuel                                                             539,589            464,802           479,603
------------------------------------------------------------------------------------------------------------------------
Net Revenues                                                             1,199,071          1,141,272         1,166,186
------------------------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                                              653,292            658,652           676,900
   Depreciation                                                             88,252             67,161            61,377
   Operating taxes                                                         169,746            145,585           139,694
------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                                   911,290            871,398           877,971
------------------------------------------------------------------------------------------------------------------------
Gain on the sale of property                                                 2,000                  -             1,479
Operating Income                                                       $   289,781        $   269,874       $   289,694
------------------------------------------------------------------------------------------------------------------------
Electric sales (MWH)*                                                    6,232,190          4,738,331         4,998,111
Capacity(MW)*                                                                2,450              2,200             2,200
Summer cooling degree days                                                   1,045                988             1,280
------------------------------------------------------------------------------------------------------------------------
</TABLE>

*Reflects the operations of the Ravenswood Projects only.


Executive Summary

Operating  income  increased  $19.9 million for the twelve months ended December
31, 2004 compared to the same period last year,  due primarily to an increase in
net revenues from the Ravenswood Projects of $53.8 million,  partially offset by
higher  depreciation  expense and operating  taxes.  In addition,  also in 2004,
KeySpan recognized a gain of $2.0 million on the sale of a parcel of land in Far
Rockaway, Queens, to LIPA.

Operating  income  decreased  $19.8 million for the twelve months ended December
31,  2003  compared  to the  same  period  of  2002,  primarily  due  to  higher
postretirement expenses of $9.0 million. In addition, in 2002 we settled certain
outstanding  issues with LIPA and The  Consolidated  Edison  Company of New York
that resulted in a $13.0 million decrease to operating expenses in 2002.

Net Revenues

Total  electric  net revenues  realized  during 2004 were $57.8  million,  or 5%
higher than such  revenues  realized  during  2003.  This  increase is primarily
attributable to the operation of the Ravenswood Expansion.

Net revenues from the Ravenswood  Projects  increased  $53.8 million,  or 18% in
2004 compared to 2003 reflecting  increased  capacity revenues of $19.1 million,
as well as higher  energy  margins of $34.7  million.  The  increase in capacity
revenues  for  the  twelve  months  ended  December  31,  2004  compared  to the
corresponding   period  last  year  primarily  reflects  the  operation  of  the
Ravenswood  Expansion.  (See the  discussion  below under "Other  Matters" for a
description of the Ravenswood Expansion.)


                                       54
<PAGE>


The increase in energy  margins for the twelve  months ended  December 31, 2004,
reflects a 32% increase in the level of megawatt hours ("MWh") sold into the New
York Independent System Operator ("NYISO") energy market, as well as an increase
of 9% in realized  "spark-spreads"  (the selling price of  electricity  less the
cost of fuel,  plus  hedging  gains or losses).  The  increase  in energy  sales
quantities reflects the operations of the Ravenswood  Expansion.  As measured in
cooling  degree-days,  weather  during  the  peak  summer  months  of  2004  was
approximately  6% warmer  than last year,  but 7% cooler than  normal.  Further,
energy sales  quantities in 2003 were adversely  impacted by the scheduled major
overhaul of our largest electric 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  Projects.  Further,  we have  engaged in the use of
derivative  financial  hedging  instruments  to hedge the cash flow  variability
associated  with  a  portion  of  forecasted  electric  energy  sales  from  the
Ravenswood  Projects.  These derivative  instruments  resulted in hedging gains,
which are reflected in net electric  margins,  of $23.0 million in 2004 compared
to hedging gains of $12.3 million for 2003. The benefits  derived from KeySpan's
hedging strategy  contributed to an increase in realized  spark-spreads  despite
the  cooler  weather  during  the  peak  summer  months.  (See  Note  8  to  the
Consolidated  Financial Statements "Hedging and Derivative Financial Instruments
and Fair Values" as well as Item 7A.  Quantitative  and Qualitative  Disclosures
about Market Risk for further information").

The rules and  regulations  for  capacity,  energy sales and the sale of certain
ancillary  services  to the NYISO  energy  markets  continue  to evolve  and the
Federal  Energy  Regulatory   Commission  ("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.  (See  the  caption  "Market  and  Credit  Risk
Management Activities" for a further discussion of these matters.)

Net revenues from the service agreements with LIPA, including the power purchase
agreements  associated  with two electric  peaking  facilities,  increased  $5.3
million for the twelve months ended  December 31, 2004,  compared to 2003.  This
increase reflects,  in part,  recovery from LIPA of approximately $26 million in
higher property taxes and depreciation  charges.  These recoveries had no impact
on  operating  income  since  actual  property  taxes and  depreciation  charges
increased by a like amount. Further, comparative revenues reflect adjustments to
the cost recovery mechanism in the LIPA Service Agreements to match actual costs
incurred with recovery of such costs. These adjustments reduced revenues in 2004
by approximately $10 million compared to 2003. These adjustments to revenues had
no impact on operating  income since actual  operating costs decreased by a like
amount. Excluding these two items, net revenues from the service agreements with
LIPA decreased approximately $10 million in 2004, compared to 2003, reflecting a
lower level of off-system sales and emission  credits,  both of which are shared
with LIPA. In 2004 we earned $16.4 million associated with non-cost  performance
incentives provided for under these agreements, compared to $16.2 million earned
in 2003. (For a description of the LIPA Agreements, see the discussion under the
caption "LIPA Agreements.")


                                       55
<PAGE>


In addition to the above,  net revenues from our electric  marketing  activities
were slightly lower in 2004 compared to 2003.

Total electric net revenues  decreased  $24.9 million,  or 2% 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  increases in the level of capacity sold
and in the selling  price of  capacity.  Such  increases  were the result of two
measures. First, in 2002, the 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 methodology,  and prior to the 2002/2003 winter season capacity auction,
corrected the  calculation  methodology to ensure that  sufficient  capacity was
procured. The corrected calculation methodology 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, FERC approved the NYISO's revised capacity market
procurement design with an effective date of May 21, 2003. This revised capacity
market  procurement  design was 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 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 was  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 23% cooler than
2002. 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


                                       56
<PAGE>


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 noted earlier) 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, as previously indicated.

As noted earlier,  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  Projects,  as well as to hedge the cash
flow  variability  associated  with a portion of forecasted peak electric energy
sales from these facilities.  These derivative  instruments  resulted in hedging
gains,  which were 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.)

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 in 2002.
Included in  revenues  for 2003 were  billings  to LIPA for certain  third party
costs that were lower than such billings in 2002.  These revenues had 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 2002. 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 in 2002.

Net  revenues  from the  peaking  facilities  were $9.6  million  higher in 2003
compared to 2002,  reflecting  a full year of  operation.  The  facilities  were
placed in  service on June 1, 2002 and 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.

The remaining  decrease in net revenues  reflects lower net revenues  associated
with KeySpan's electric marketing subsidiary.

Operating Expenses

Total  operating  expenses  increased  $39.9 million,  or 5%, for the year-ended
December 31, 2004 compared to the same period of 2003,  due to higher  operating
taxes  and  depreciation  charges,  partially  offset  by lower  operations  and
maintenance expenses.  Operations and maintenance expense decreased $5.3 million
reflecting, in part, $10 million in lower costs associated with the LIPA Service
Agreements as noted earlier.  Operations and  maintenance  expense also reflects
the impact of FIN 46 which required KeySpan to consolidate the Ravenswood Master
Lease and classify the lease  obligation as long-term  debt on the  Consolidated
Balance Sheet.  Further, an asset was recorded 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. As a result of


                                       57
<PAGE>


implementing FIN 46, beginning  January 1, 2004, lease payments  associated with
the  Ravenswood  Master  Lease have been  reflected  as interest  expense on the
Consolidated  Statement of Income and the leased  assets are being  depreciated.
The  reclassification  of lease payments  associated with the Ravenswood  Master
Lease to interest expense  resulted in a comparative  decrease to operations and
maintenance expense of $30 million. However, KeySpan incurred lease costs of $11
million associated with the sale/leaseback  transaction involving the Ravenswood
Expansion,  that went  into  effect  May 2004.  In  addition,  KeySpan  incurred
increased repair and maintenance costs, including removal costs, associated with
the Ravenswood Projects,  as well as higher postretirement costs, which, for the
most part, offset the beneficial impact of FIN 46.

The increase in depreciation  expense of $21.1 million  primarily relates to the
depreciation  of the leased  assets  under the  Ravenswood  Master  Lease  which
increased  depreciation by $16 million.  The remaining  increase in depreciation
expense is associated with KeySpan's Long Island based electric generating units
and is fully recoverable from LIPA. The higher operating taxes primarily reflect
an increase in property  taxes which are fully  recoverable  from LIPA, as noted
earlier.

Operating  expenses decreased $6.6 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
earlier.  Excluding the decrease in these costs,  operating  expenses  increased
approximately $23 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 two peaking facilities.

Other Matters

The Ravenswood  Expansion,  a 250 MW combined  cycle  generating  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 and in May 2004 the facility began full commercial
operations.  The entire  capacity and energy  produced  from this plant is being
sold into the NYISO markets.

To finance  this  facility,  KeySpan  entered into a leveraged  lease  financing
arrangement.  In May  2004,  the  facility  was  acquired  by a lessor  from our
subsidiary,  KeySpan Ravenswood,  LLC, and simultaneously leased back to it. All
the  obligations  of our  subsidiary  under the lease have been  unconditionally
guaranteed by KeySpan.  This lease  transaction  generated cash proceeds of $385


                                       58
<PAGE>


million,  before  transaction costs, which approximates the fair market value of
the facility, as determined by a third-party appraiser. The lease has an initial
term of 36 years and the yearly  operating  lease expense will be  approximately
$17 million per year.  Lease  payments will fluctuate from year to year, but are
substantially  paid  over the first 16  years.  (See Note 7 to the  Consolidated
Financial  Statements,  "Financial  Guarantees and Contingencies" for additional
information regarding this financing arrangement.)

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 would have
jointly  owned and  operated  two 250 MW electric  generating  facilities  to be
located on Long Island,  one of which is the Melville  site and the other in the
town of  Brookhaven  which also has received all permits and  approvals.  In May
2004,  LIPA  tentatively  selected  proposals  submitted by two other bidders in
response to the RFP.  KeySpan remains  committed to the Melville project and the
benefits to Long Island's  energy  future that this project  would  supply.  The
project  has  received  New York  State  Article X  approval  by having  met all
operational and environmental permitting  requirements.  Further, the project is
strategically  located  in  close  proximity  to both  the  high  voltage  power
transmission grid and the high pressure gas distribution network.

LIPA is in the process of  performing a long-term  strategic  review  initiative
regarding  its future  direction.  Some of the  strategic  options  that LIPA is
considering  include  whether  LIPA  should  continue  its  operations  as  they
presently  exist,  fully  municipalize  or privatize,  sell some, but not all of
their  assets and become a regulator of rates and  services.  Until LIPA makes a
determination  on its  future  direction,  we are unable to  determine  what the
outcome of this strategic review will have on the Melville project.  At December
31, 2004, total  capitalized  costs  associated with the siting,  permitting and
procurement  of equipment  for the Melville  facility were  approximately  $62.5
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.


                                       59
<PAGE>


Energy Services

The Energy Services segment includes  subsidiaries  that provide  energy-related
services to customers  primarily located within the Northeastern  United States,
with concentrations in the New York City and Boston metropolitan areas,  through
the  following  lines of  business:  (i) Home Energy  Services,  which  provides
residential  and small  commercial  customers  with service and  maintenance  of
energy systems and appliances  and (ii) Business  Solutions,  which now provides
operation  and  maintenance,  design,  engineering  and  consulting  services to
commercial and industrial customers.

The  table  below  highlights  selected  financial  information  for the  Energy
Services  segment.  The  December  31,  2003 and 2002 data has been  restated to
reflect certain businesses in the Business Solutions division - specifically the
mechanical contracting companies - as discontinued operations due to the sale of
these companies in January and February 2005.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
                                                                   Year Ended December 31,
(In Thousands of Dollars)                              2004                 2003                  2002
---------------------------------------------------------------------------------------------------------
<S>                                                  <C>                  <C>                   <C>
Revenues                                            $ 193,921            $ 166,375             $ 208,624
Less:  Operating expenses                             227,799              199,338               254,205
           Goodwill impairment                         14,424                    -                     -
---------------------------------------------------------------------------------------------------------
Operating  (Loss)                                   $ (48,302)           $ (32,963)            $ (45,581)
---------------------------------------------------------------------------------------------------------
</TABLE>


The Energy Services segment  incurred  operating losses of $48.3 million for the
year-ended  December 31, 2004  compared to losses of $33.0  million for the same
period last year.  As noted  earlier,  in  September  2004,  KeySpan  recorded a
non-cash goodwill impairment charge in continuing operations of $14.4 million as
a result of an  evaluation  of the carrying  value of goodwill  recorded in this
segment.  Based upon the operating  results  experienced by the Energy  Services
segment and management's  opinion that it was likely that a significant  portion
of the Energy Services segment would be sold within one year,  KeySpan conducted
an evaluation of the carrying  value of its  investments  in this segment.  That
evaluation  resulted  in a total  pre-tax  impairment  charge of $208.6  million
($152.4 million, or $0.95 per share after-tax) - $14.4 million of this charge is
attributable  to  continuing  operations,  while the  remaining  $194.2  million
($139.9  million  after-tax,   or  $0.87  per  share),  has  been  reflected  in
discontinued  operations.  (See Note 11 to the Consolidated Financial Statements
"Energy  Services -  Discontinued  Operations"  for  additional  details on this
charge.)


Excluding the goodwill impairment charge, operating income for the twelve months
ended  December  31,  2004 was  essentially  the same as 2003.  Lower  operating
results realized by Home Energy Services were offset by lower operating expenses
of the remaining Business Solutions companies.  Home Energy Services experienced
higher  operating  expenses as a result of the write-off of accounts  receivable
and contract  revenues on certain projects that were deemed to be uncollectible,
as well as the write-down of inventory balances.


                                       60
<PAGE>


Operating  results were $12.6 million better in 2003 compared to 2002 due to the
operations of the Home Energy Services group of companies. Comparative operating
results reflect 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.

Energy Investments

The Energy  Investments  segment  consists of our gas exploration and production
investments, as well as certain other domestic and international  energy-related
investments. In June 2004, KeySpan exchanged 10.8 million shares of common stock
of The  Houston  Exploration  Company  ("Houston  Exploration")  an  independent
natural gas and oil exploration  company  located in Houston,  Texas for 100% of
the stock of Seneca  Upshur  Petroleum,  Inc.  ("Seneca-Upshur"),  previously  a
wholly owned subsidiary of Houston  Exploration.  This  transaction  reduced our
interest in Houston Exploration from 55% to approximately 23.5%. As part of this
transaction,  Houston  Exploration  retired 4.6 million of its common shares and
issued  6.8  million  new  shares  in  a  public  offering.   Based  on  Houston
Exploration's  announced  offering  price of $48.00 per  share,  Seneca-Upshur's
shares  were  valued at the  equivalent  of $449  million,  or $41.57 per share.
Seneca-Upshur's  assets  consisted  of West  Virginia gas  producing  properties
valued at $60 million,  and $389 million in cash.  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,  this
transaction  resulted in a gain to KeySpan of $150.1 million.  Effective June 1,
2004,  Houston  Exploration's  earnings  and our  ownership  interest in Houston
Exploration  were  accounted  for  on  the  equity  basis  of  accounting.   The
deconsolidation  of Houston  Exploration  required  the  recognition  of certain
deferred  taxes on our  remaining  investment  resulting  in a net  deferred tax
expense of $44.1 million. Therefore, the net gain on the share exchange less the
deferred tax provision was $106 million, or $0.66 per share.

In  November  2004,  KeySpan  sold  its  remaining  23.5%  interest  in  Houston
Exploration  (6.6 million  shares) and received cash  proceeds of  approximately
$369  million.  KeySpan  recorded  a  pre-tax  gain of $179.6  million  which is
reflected  in other income and  (deductions)  on the  Consolidated  Statement of
Income. The after-tax gain was $116.8 million or $0.73 per share.

Our gas  exploration  and  production  activities  now include our  wholly-owned
subsidiaries Seneca-Upshur and KeySpan Exploration and Production, LLC ("KeySpan
Exploration and  Production"),  which is engaged in a joint venture with Houston
Exploration.

In the  second  quarter  of 2004,  KeySpan  recorded  a $48.2  million  non-cash
impairment  charge to recognize the reduced  valuation of proved  reserves.  See
Note  1  to  the  Consolidated  Financial  Statements  "Summary  of  Significant
Accounting   Policies"  Item  F  "Gas  Exploration  and  Production  Property  -
Depletion" for further information on this charge.

Asset  transactions  regarding our investment in Houston  Exploration  were also
recorded in 2003. 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


                                       61
<PAGE>


realized net proceeds of $79 million in connection with this repurchase. 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.

Selected  financial data and operating  statistics for our gas  exploration  and
production  activities  is set  forth in the  following  table  for the  periods
indicated.  Operating  income represents  100% of our gas exploration and
production  subsidiaries' results for all periods prior to May 31, 2004 and five
months of equity  earnings (June 1, 2004 through October 31, 2004) for our 23.5%
interest in Houston Exploration.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                                                                             Year Ended December 31,
(In Thousands of Dollars)                                           2004                 2003                  2002
---------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>                   <C>                  <C>
Revenues                                                        $ 279,999             $ 501,255            $ 357,451
Less:  Depletion and amortization expense                         108,791               204,102              176,925
           Full cost ceiling test write-down                       48,190                     -                    -
           Other operating expenses                                49,320                99,944               70,267
Plus: Equity earnings                                              20,757                     -                    -
---------------------------------------------------------------------------------------------------------------------
Operating Income                                                 $ 94,455             $ 197,209            $ 110,259
---------------------------------------------------------------------------------------------------------------------
</TABLE>


Executive Summary

Operating  income  decreased  $102.8 million in 2004 compared to 2003 reflecting
KeySpan's  lower  ownership  in Houston  Exploration  during  the year,  and its
ultimate sale as discussed above.

Operating  income  increased  $87.0  million  in 2003  compared  to 2002  due to
significantly  higher  average  realized  gas prices and a moderate  increase in
production  volumes offset, to some extent, by an increase in operating expenses
associated  with a higher  depletion  rate,  as well as higher  lease  operating
expenses and severance taxes.

Operating Income

The decline in operating  income of $102.8  million for the twelve  months ended
December 31, 2004  compared to the  corresponding  period in 2003,  reflects the
reduction in KeySpan's ownership interest in Houston  Exploration.  As noted, in
2003 KeySpan  maintained a 55%  ownership  interest in Houston  Exploration.  In
2004,  KeySpan  maintained  a 55%  ownership  interest for the five month period
January 1, 2004 through May 31, 2004,  then held an  approximate  23.5% interest
for the five month  period June 1, 2004 through  October 31, 2004.  KeySpan sold
its remaining 23.5% interest in Houston  Exploration in November 2004.  Further,
the  reduction  in  operating  income in 2004 also  reflects  the $48.2  million
non-cash  impairment  charge recorded by KeySpan's  wholly-owned gas exploration
and production subsidiaries to reflect the reduced valuation of proved reserves,
as noted above.


                                       62
<PAGE>


Seneca-Upshur utilizes  over-the-counter  ("OTC") natural gas swaps to hedge the
cash flow  variability  associated  with  forecasted  sales of a portion  of its
natural gas production.  At December 31, 2004, Seneca-Upshur has hedge positions
in  place  for  approximately  85%  of  its  estimated  2005  through  2007  gas
production,  net of gathering  costs. We use forward index prices to value these
swap positions.  (See Note 8 to the Consolidated  Financial Statements "Hedging,
Derivative  Financial  Instruments  and Fair Values" for further  details on the
derivative financial instruments.)

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

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 reflected  downward
reserve revisions related to performance,  the addition of more costs to Houston
Exploration's  depletion  base with fewer  additions of 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  were  increasing  as new  wells and
facilities were added and production from existing wells was maintained.


                                       63
<PAGE>


For much of 2004,  subsidiaries in this segment also held an ownership  interest
in  certain  midstream  natural  gas assets in Western  Canada  through  KeySpan
Canada.  These assets  included 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.  At the beginning of 2004, KeySpan
held a 60.9% ownership  interest in KeySpan Canada.  In April 2004,  KeySpan and
KeySpan  Facilities  Income Fund (the "Fund"),  an open-ended  income fund trust
which previously owned the other 39.1% interest in KeySpan Canada, consummated a
transaction whereby the Fund sold 15.617 million units of the Fund at a price of
CDN$12.60 per unit for gross total proceeds of approximately  CDN$196.8 million.
The  proceeds  of the  offering  were used by the Fund to acquire an  additional
35.91%  interest in KeySpan  Canada from  KeySpan.  We received  net proceeds of
approximately  CDN$186.3  million  (or  approximately  US$135  million),   after
commissions and expenses.  The Fund's ownership in KeySpan Canada increased from
39.1% to 75%, and KeySpan's  ownership of KeySpan Canada decreased from 60.9% to
25%. KeySpan recorded a gain of $22.8 million ($10.1 million after-tax, or $0.06
per  share)  on this  transaction.  Effective  April 1,  2004  KeySpan  Canada's
earnings and our ownership  interest in KeySpan Canada had been accounted for on
the equity basis of accounting.

In July 2004, the Fund issued an additional 10.7 million units,  the proceeds of
which  were used to fund the  acquisition  of the  midstream  assets of  Chevron
Canada  Midstream  Inc.  This  transaction  had the effect of  further  diluting
KeySpan's ownership of KeySpan Canada to 17.4%.

In December 2004, KeySpan sold its remaining 17.4% interest in KeySpan Canada to
the Fund and received net proceeds of approximately  $119 million and recorded a
pre-tax  gain  of  $35.8  million,  which  is  reflected  in  other  income  and
(deductions)  on the  Consolidated  Statement of Income.  The after-tax gain was
approximately $24.7 million, or $0.15 per share.

Asset transactions regarding our investment in KeySpan Canada were also recorded
in 2003.  In 2003, we sold a portion of our interest in KeySpan  Canada  through
the Fund. The Fund acquired a 39.1% ownership interest in KeySpan Canada through
an indirect  subsidiary,  and then  issued 17 million  trust units to the public
through an initial  public  offering.  Each trust unit  represented a beneficial
interest in the Fund and was  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 was 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.

This segment is also  engaged in pipeline  development  activities.  KeySpan and
Duke  Energy  Corporation  each own a 50%  interest in  Islander  East  Pipeline
Company,  LLC  ("Islander  East").  Islander  East was  created  to  pursue  the
authorization  and  construction  of an interstate  pipeline  from  Connecticut,
across Long Island Sound,  to a terminus  near  Shoreham,  Long Island.  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.  Further,  in August 2004, KeySpan
acquired a 21% interest in the Millennium  Pipeline project which will transport
up to 500,000 DTH of natural gas a day from Corning to Ramapo,  New York,  where
it will connect to an existing pipeline.


                                       64
<PAGE>


Additionally,  subsidiaries  in this segment  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 the KeySpan LNG facility
in Providence,  Rhode Island, a 600,000 barrel liquefied natural gas storage and
receiving  facility.  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 addition to the asset sales noted previously, KeySpan anticipates selling its
50% interest in PTL, a gas pipeline from southwest Scotland to Northern Ireland.
On February 25, 2005,  KeySpan entered into a Share Sale and Purchase  Agreement
with BG Energy Holdings Limited and Premier Transmission  Financing plc ("PTF"),
pursuant to which all of the  outstanding  shares of PTL are to be  purchased by
PTF.  It is  expected  that the sale of our 50%  interest  in PTL will result in
proceeds of approximately $42.5 million and that the closing of this transaction
will occur before the end of the second  quarter of 2005. In the fourth  quarter
of 2004, KeySpan recorded a pre-tax non-cash  impairment charge of $26.5 million
- $18.8 million after-tax or $0.12 per share,  reflecting the difference between
the  anticipated  cash  proceeds  from the sale of PTL  compared to its carrying
value. This investment is also accounted for under the equity method.

In the fourth  quarter of 2003, we completed the sale of our then 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.

Selected financial data for our other energy-related investments is set forth in
the following table for the periods indicated. Operating income below represents
100% of KeySpan  Canada's  results  for three  months  ended  March 31, 2004 and
equity earnings from April 1, 2004 through November 30, 2004.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
                                                                     Year Ended December 31,
(In Thousands of Dollars)                                   2004              2003               2002
-------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>                 <C>
Revenues                                                 $ 46,988         $ 113,124           $ 90,778
Less: Operation and maintenance expense                    33,453            68,568             57,161
      Other operating expenses                              7,556            22,317             17,622
      Impairment charge                                    26,541                 -                  -
Add:  Equity earnings                                      25,779            19,106             13,992
      Gain on sale of property                              5,021                 -              2,348
-------------------------------------------------------------------------------------------------------
Operating Income                                         $ 10,238          $ 41,345           $ 32,335
-------------------------------------------------------------------------------------------------------
</TABLE>

The  decrease  in  comparative  operating  income in 2004  compared to last year
reflects the impairment charge associated with our investment in PTL, as well as
our lower ownership interest in KeySpan Canada.  Operating income from our other
energy-related investments in 2004 was substantially the same as 2003.

The increase in operating  income in 2003  compared to 2002  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


                                       65
<PAGE>


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 the KeySpan LNG storage  facility  located in Rhode
Island, which we acquired in December 2002.

Allocated Costs

As  previously  mentioned,  KeySpan  is  subject  to  the  jurisdiction  of  the
Securities  and Exchange  Commission  ("SEC") under the Public  Utility  Holding
Company Act  ("PUHCA")  as  amended.  Under  PUHCA,  the SEC  regulates  various
transactions  among  affiliates  within a holding company system.  In accordance
with the SEC's  regulations  under PUHCA and the New York State  Public  Service
Commission,  we have service companies that provide:  (i) traditional  corporate
and administrative services; (ii) gas and electric transmission and distribution
systems planning,  marketing, and gas supply planning and procurement; and (iii)
engineering and surveying services to subsidiaries.  Operating income variations
reflected  in  "eliminations  and other"  associated  with  these  non-operating
subsidiaries  reflect,  in part,  allocation  adjustments  recorded in 2003.  As
required  by  the  SEC,  during  2003  we  adjusted  certain  provisions  in our
allocation  methodology  that resulted in certain costs being  allocated back to
certain  non-operating   subsidiaries.   Further,  in  2004  KeySpan  reached  a
settlement  with its  insurance  carriers  regarding  cost recovery for expenses
incurred at a non-utility  environmental site and recorded an $11.6 million gain
from the settlement as a reduction to operating expenses.

The variation in operating income for these non-operating  subsidiaries  between
2003 and 2002 primarily reflects a $10 million favorable  adjustment recorded in
2003 for environmental reserves associated with non-utility  environmental sites
based on a site investigation study concluded in the fourth quarter of 2003.

Liquidity

Cash flow from operations for the year ended December 31, 2004 decreased  $473.3
million,  or 39%, compared to 2003 primarily due to federal tax refunds received
in 2003.  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 for 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
compared with federal tax payments made in 2004 of $63.2 million,  resulted in a
comparative cash flow decrease in 2004 of approximately $340.5 million. Further,
cash flow from operations for 2004 was adversely impacted by the deconsolidation
of Houston Exploration in June 2004.

On October 26,  2004,  the  American  Jobs  Creation Act of 2004 (the "Act") was
enacted into law. A significant  provision of the Act, as it relates to KeySpan,
is the 85% dividend deduction for dividends received from foreign  corporations.
The Act allows  KeySpan to  tax-effectively  bring  funds  invested  outside the
United States back into the United States. At December 31, 2004 KeySpan had $360
million of temporary cash investments outside the United States. KeySpan intends
to repatriate this cash in 2005.


                                       66
<PAGE>


Cash flow from operations for the year ended December 31, 2003 increased  $475.7
million,  or 64%,  compared to 2002.  As noted above,  in 2003 KeySpan  received
approximately  $277.3 in federal  tax  refunds.  These  refunds  compared to 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 of 2003,
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
refill natural gas storage levels as a result of the higher natural gas prices.

At December 31,  2004,  we had cash and  temporary  cash  investments  of $922.0
million.  During 2004,  we borrowed an additional  $430.3  million of commercial
paper  and,  at  December  31,  2004,  $912.2  million of  commercial  paper was
outstanding at a weighted-average  annualized  interest rate of 2.4%. We had the
ability to borrow up to an additional  $388 million at December 31, 2004,  under
the terms of our credit facility.  As discussed in more detail under the caption
"Financing",  in  January  2005  KeySpan  used a portion of its  temporary  cash
investments to redeem $500 million of previously outstanding long-term debt.

In June 2004, KeySpan completed the restructuring of its credit  facilities.  We
entered into a new $640 million five year revolving  credit  facility to replace
the $450  million,  364 day facility  which expired in June. We also amended our
existing  three year $850 million  facility due June 2006 to reduce  commitments
thereunder  by $190  million  to a new  level of $660  million.  The two  credit
facilities total $1.3 billion and are each syndicated among sixteen banks. These
facilities  continue to support  KeySpan's  commercial paper program for working
capital needs.

The fees for these  facilities  are  subject to a  ratings-based  grid,  with an
annual fee of 0.08% on the new  five-year  facility  and 0.125% on the  existing
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 in the five-year facility are based on
the  Eurodollar  rate  plus a margin  of 0.40%  for loans up to 33% of the total
five-year  facility,  and an  additional  0.125% for loans over 33% of the total
five-year facility. In the three-year facility Eurodollar loans are based on the
Eurodollar  rate  plus a margin  of  0.625%  for  loans  up to 33% of the  total
three-year  facility,  and an additional  0.125% for loans over 33% of the total
three-year  facility.  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%. Competitive
bid loans are based on bid results requested by KeySpan from the lenders.  We do
not anticipate borrowing against these facilities; however, if the credit rating
on our commercial paper program were to be downgraded, it may be necessary to do
so.


                                       67
<PAGE>


The facilities  contain 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% until the
expiration of the existing three-year facility in 2006, at which time it will be
lowered to 62%.  Violation of this covenant  could result in the  termination of
the facilities and the required  repayment of amounts  borrowed  thereunder,  as
well as possible cross defaults under other debt agreements.

Under the terms of the credit agreements, KeySpan's debt-to-total capitalization
ratio  reflects  80% equity  treatment  for the MEDS Equity  Units issued in May
2002. At December 31, 2004, consolidated  indebtedness,  as calculated under the
terms of the credit agreements was 53.4% of consolidated capitalization.

Houston Exploration and KeySpan Canada also had revolving credit facilities with
commercial banks. During the time period that Houston Exploration's results were
consolidated  with  KeySpan's  (the  five  months  ended May 31,  2004)  Houston
Exploration  borrowed  $49  million  under its credit  facility  and repaid $136
million. KeySpan Canada repaid $17.7 million under its facility during the first
three  months of 2004 (the time  period in which its results  were  consolidated
with   KeySpan's).   These   borrowings  and  repayments  are  included  in  the
Consolidated Cash Flow Statement.

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.  Additionally,  our KEDNE gas
supply is concentrated with Merrill Lynch Trading.  Accordingly,  our cash flows
are dependent  upon the timely  payment or delivery of amounts or commodity owed
to us by these counterparties.

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.

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)                   2004                   2003
--------------------------------------------------------------------------
Gas Distribution                         $ 414,522            $   419,549
Electric Services                          150,320                256,498
Energy Investments                         160,225                314,097
Energy Services and other                   25,262                 19,249
--------------------------------------------------------------------------
                                         $ 750,329            $ 1,009,393
--------------------------------------------------------------------------


                                       68
<PAGE>


Construction  expenditures related to the Gas Distribution segment are primarily
for  the  renewal,   replacement  and  expansion  of  the  distribution  system.
Construction  expenditures  for the Electric  Services  segment  reflect cost to
maintain our  generating  facilities  and  construct the  Ravenswood  Expansion.
Construction  expenditures  related to the Energy Investments  segment primarily
reflect  costs  associated  with  gas  exploration  and  production  activities,
including  those of Houston  Exploration  through May 31, 2004, as well as costs
related to KeySpan Canada's gas processing facilities through April 1, 2004. The
decrease in capital expenditures in 2004 compared to 2003 primarily reflects the
lower ownership  interest in Houston  Exploration,  as well as the completion of
the Ravenswood Expansion in May 2004.

Construction  expenditures  for  2005 are  estimated  to be  approximately  $650
million.  The  amount of future  construction  expenditures  is  reviewed  on an
ongoing  basis and can be  affected by timing,  scope and changes in  investment
opportunities.

Financing

In August 2004, KeySpan redeemed approximately $758 million of outstanding debt.
The table below indicates the various series of debt redeemed and the associated
KeySpan subsidiary:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------
KeySpan Subsidiary                      Series                     Due Date                  Amount ($000)
------------------------------------------------------------------------------------------------------------------
<S>                              <C>                                <C>                       <C>
KeySpan Corporation                7.25% Medium Term Notes           November 2005           $ 700,000
EnergyNorth Natural Gas            9.70% Series B                    September 2019              7,000
EnergyNorth Natural Gas            9.75% Series C                    September 2020             10,000
EnergyNorth Natural Gas            8.44% Series D                    January 2009                1,667
EnergyNorth Natural Gas            7.40% Series E                    September 2027             21,285
Essex Gas Company                 10.10% Series 1990                 December 2020               8,000
Essex Gas Company                  7.28% Series 1996                 December 2016              10,000
------------------------------------------------------------------------------------------------------------------
                                                                                             $ 757,952
------------------------------------------------------------------------------------------------------------------
</TABLE>

KeySpan   incurred  $54.5  million  in  call  premiums   associated  with  these
redemptions,  of which  $45.9 was  expensed  and  recorded  in other  income and
deductions on the Consolidated  Statement of Income. The remaining amount of the
call premiums have been deferred for future recovery. Further, KeySpan wrote-off
$8.2 million of previously deferred financing costs which have been reflected in
interest  expense on the Consolidated  Statement of Income.  The total after-tax
expense of the debt redemption was $29.3 million or $0.18 per share.

During the third quarter of 2004,  KEDNY retired $8.0 million of its outstanding
Gas Facilities Revenue Bonds. The funds used to retire this debt were drawn from
a  special   deposit   defeasance   trust   previously   established  by  KEDNY.
Approximately $640 million of Gas Facilities Revenue Bonds remain outstanding.


                                       69
<PAGE>


In August 2004, KeySpan redeemed 83,268 shares of preferred stock 6.00% Series A
par value  $100  that were  previously  issued in a private  placement.  KeySpan
redeemed  these shares at a 2% premium and incurred a cash  expenditure  of $8.5
million.

In addition, on January 14, 2005, KeySpan redeemed $500 million 6.15% Series due
2006 of outstanding  debt.  KeySpan  incurred $20.9 million in call premiums and
wrote-off $1.0 million of previously deferred financing costs. Further,  KeySpan
accelerated  the  amortization  of  approximately  $10.5  million of  previously
unamortized  benefits  associated with an interest rate swap on these bonds. The
accelerated  amortization  was  recorded  as a reduction  to  interest  expense.
Further, $55.3 million 7.07% Series B of mandatory redeemable preferred stock is
scheduled to be redeemed in May 2005.

During the second  quarter  of 2004,  KeySpan  entered  into a  leveraged  lease
financing arrangement associated with the Ravenswood Expansion. In May 2004, the
facility was acquired by a lessor from our subsidiary,  KeySpan Ravenswood, LLC,
and simultaneously leased back to that subsidiary. All of the obligations of our
subsidiary under the lease have been unconditionally guaranteed by KeySpan. This
lease transaction  generated cash proceeds of $385 million,  before  transaction
costs, which approximates fair market value of the facility,  as determined by a
third-party  appraiser.  (See Note 7 to the Consolidated  Financial  Statements,
"Contractual Obligations, Financial Guarantees and Contingencies" for additional
information regarding this financing arrangement.)

In October 2004, KeySpan filed a new universal shelf  Registration  Statement to
issue,  from time to time, up to $3 billion in  securities.  We will continue to
evaluate our capital structure and financing strategy for 2005 and beyond.

The following table represents the ratings of our long-term debt at December 31,
2004. During the fourth quarter of 2004 Standard & Poor's reaffirmed its ratings
on  KeySpan's  and its  subsidiaries'  long-term  debt and removed its  negative
outlook. Moody's Investor Services,  however, continues to maintain its negative
outlook ratings on KeySpan's and its subsidiaries' long-term debt.

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


                                       70
<PAGE>


Off-Balance Sheet Arrangements

Guarantees

KeySpan has a number of financial  guarantees with its  subsidiaries at December
31, 2004. KeySpan had fully and unconditionally  guaranteed: (i) $525 million of
medium-term  notes issued by KEDLI;  (ii) the obligations of KeySpan  Ravenswood
LLC, which is the lessee under the $425 million Master Lease associated with the
Ravenswood Facility and the lessee under the sale/leaseback  transaction for the
Ravenswood  Expansion;  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  Authorities for the construction of two
electric-generation  peaking  facilities on Long Island.  The medium-term notes,
the Master Lease and the  tax-exempt  bonds are  reflected  on the  Consolidated
Balance  Sheet;   the   sale/leaseback   transaction  is  not  recorded  on  the
Consolidated  Balance Sheet.  Further,  KeySpan has  guaranteed:  (i) up to $258
million of surety bonds associated with certain construction  projects currently
being performed by former subsidiaries within the Energy Services segment;  (ii)
certain  supply  contracts,  margin  accounts  and  purchase  orders for certain
subsidiaries  in an aggregate  amount of $74  million;  and (iii) $74 million of
subsidiary  letters  of  credit.  These  guarantees  are  not  recorded  on  the
Consolidated  Balance Sheet.  KeySpan's  guarantees on certain performance bonds
relating  to  current  construction  projects  of  the  discontinued  mechanical
contracting  companies will remain in place throughout the construction  period.
It is contemplated  that the majority of the current contracts will be completed
by the end of 2005.  KeySpan has  received an  indemnity  bond issued by a third
party to offset  potential  exposure  related  to a  significant  portion of the
continuing  guarantee.  At this  time,  we have no  reason to  believe  that our
subsidiaries or former  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,  as well as Note 11 "Energy Services
-  Discontinued  Operations"  for  additional  information  on the  discontinued
mechanical contracting companies.)

Contractual Obligations

KeySpan has certain contractual obligations related to its outstanding long-term
debt,  outstanding  credit facility  borrowings,  outstanding  commercial  paper
borrowings, various 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 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."


                                       71
<PAGE>


The  table  below  reflects   maturity   schedules  for  KeySpan's   contractual
obligations  at December 31, 2004.  Included in the table is the long-term  debt
that has been  consolidated as part of the variable  interest entity  associated
with the Ravenswood Master Lease.

<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                                       $ 4,442,450        $   527,000       $ 1,017,250            $ 2,898,200
 Capital Leases                                            11,833              3,172             2,326                  6,335
 Operating Leases                                         411,149            190,961           124,529                 95,659
 Master Lease Payments                                    128,189             85,459            42,730                      -
 Sale/Leaseback Arrangement                               598,920             69,375            72,430                457,115
 Preferred Stock Redeemable                                75,000             75,000                 -                      -
 Interest Payments                                      2,680,715            679,487           396,612              1,604,616
 Demand Charges                                           485,209            485,209                 -                      -
------------------------------------------------------------------------------------------------------------------------------
 Total Contractual
     Cash Obligations                                 $ 8,833,465        $ 2,115,663       $ 1,655,877            $ 5,061,925
------------------------------------------------------------------------------------------------------------------------------
 Commercial Paper                                     $   912,246          Revolving
------------------------------------------------------------------------------------------------------------------------------
</TABLE>

For information regarding projected post retirement contributions, see Note 4 to
the Consolidated Financial Statements "Post Retirement Benefits."

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.


                                       72
<PAGE>


Valuation of Goodwill

KeySpan records  goodwill on purchase  transactions,  representing the excess of
acquisition  cost over the fair value of net  assets  acquired.  In testing  for
goodwill  impairment  under SFAS 142  "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.

As  prescribed  in SFAS 142,  KeySpan is required to compare the fair value of a
reporting unit to its carrying amount,  including  goodwill.  This evaluation is
required to be  performed  at least  annually,  unless  facts and  circumstances
indicated  that the  evaluation  should be performed at an interim period during
the  year.  Prior to this  evaluation,  the  recorded  goodwill  for the  Energy
Services segment,  as a result of prior  acquisitions,  was  approximately  $173
million.

The Energy  Services  segment  has  experienced  significantly  lower  operating
profits  and cash flows  than  originally  projected.  As  previously  reported,
management reviewed the operating performance of this segment. At a meeting held
on November 2, 2004, KeySpan's Board of Directors authorized management to begin
the process of disposing of a significant  portion of its ownership interests in
certain  companies  within  the Energy  Services  segment -  specifically  those
companies engaged in mechanical contracting activities.  In January and February
of 2005, KeySpan sold its mechanical contracting companies.

During 2004 KeySpan  conducted an evaluation  of the carrying  value of goodwill
recorded in its Energy Services segment. As a result of this evaluation, KeySpan
recorded a non-cash goodwill  impairment charge of $108.3 million ($80.3 million
after tax, or $0.50 per share) in 2004. This charge was recorded as follows: (i)
$14.4 million as an operating  expense on the  Consolidated  Statement of Income
reflecting the write-down of goodwill on Energy  Services  segment's  continuing
operations;  and (ii) $93.9 million as  discontinued  operations  reflecting the
impairment  on  the  mechanical  contracting   companies.   KeySpan  employed  a
combination of two methodologies in determining the estimated fair value for its
investment in the Energy Services  segment,  a market valuation  approach and an
income valuation approach. Under the market valuation approach, KeySpan utilized
a range of near-term potential realizable values for the mechanical  contracting
businesses.  Under the income valuation approach, the fair value was obtained by
discounting  the sum of (i) the expected future cash flows and (ii) the terminal
value.   KeySpan  was   required  to  make  certain   significant   assumptions,
specifically the  weighted-average  cost of capital,  short and long-term growth
rates and expected future cash flows. (See Note 11 to the Consolidated Financial
Statements "Energy Services-Discontinued Operations" for further details.)


                                       73
<PAGE>


In  addition  to the  goodwill  evaluation  conducted  for the  Energy  Services
segment,  KeySpan  conducted  evaluations  of the  goodwill  recorded in the Gas
Distribution and Energy Investments  segments.  Based on KeySpan's evaluation of
the fair value of the Gas  Distribution  unit,  KeySpan  concluded that the fair
value of the Gas Distribution unit exceeded the carrying value and no impairment
was  necessary.  As noted  previously,  KeySpan has entered into an agreement to
sell its 50% interest in PTL before the end of the second quarter of 2005.  This
investment  is accounted for under the equity method of accounting in the Energy
Investments  segment.  In the fourth quarter of 2004 KeySpan  recorded a pre-tax
non-cash  impairment  charge of $26.5 million - $18.8 million after-tax or $0.12
per share.  The impairment  charge reflects the difference  between  anticipated
cash  proceeds  from the sale of PTL  compared  to its  carrying  value  and was
recorded as a reduction to goodwill.

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 ("MADTE").

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 MADTE, 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.

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, 2004 could  result in a charge to net income of  approximately
$313 million or $1.95 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.


                                       74
<PAGE>


As is further  discussed  under the caption  "Regulation  and Rate  Matters," in
October 2003 the MADTE  rendered its decision on the Boston Gas  Company's  base
rate case and  Performance  Based Rate Plan  proposal  submitted to the MADTE in
April  2003.  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 rate plans for KEDNY and KEDLI.
The ultimate resolution of any future rate plans could have a significant impact
on the  application  of SFAS  71 to  these  entities  and,  accordingly,  on our
financial  position,  results of operations and cash flows.  EnergyNorth Natural
Gas, Inc.'s base rates continue as set by the NHPUC in 1993. 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  changes  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.

For 2004,  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 performance of equity and fixed income investments
over long periods of time. The actual 10 year compound annual rate of return for
the KeySpan Plans is greater than 8.5%.


                                       75
<PAGE>


KeySpan's master trust investment allocation policy target is 70% equity and 30%
fixed income. At December 31, 2004, the actual investment allocation was in line
with the  target.  In an effort  to  maximize  plan  performance,  actual  asset
allocation  will  fluctuate  from  year to year  depending  on the then  current
economic environment.

Based  on the  results  of an  asset  and  liability  study  conducted  in  2003
projecting  asset returns and expected  benefit  payments over a 10-year period,
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 performance 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 2004 expense by approximately $6 million, before
deferrals.

The  year-end  December  31,  2004  assumed  discount  rate  used  to  determine
postretirement  obligations  was 6%. 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 2004  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 5.75% would have  required an  additional  $38 million debit to
other  comprehensive  income  ("OCI")  before  taxes and  deferrals.  A year-end
discount rate of 5.5% would have  required an  additional  $290 million debit to
OCI before taxes and deferrals.

At January 1, 2004, the assumed  discount rate used to determine  postretirement
obligations  was 6.25%.  A 25 basis  point  increase  or decrease in the assumed
discount  rate at the  beginning of the year would have impacted 2004 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, 2004, 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 2004.  However,  although we have presently  exceeded
ERISA  funding  requirements,  our pension  plans,  on an actuarial  basis,  are
currently underfunded.  Therefore,  during 2004 KeySpan contributed $186 million
to its funded and unfunded postretirement plans.

For 2005, KeySpan expects to contribute approximately $120 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.


                                       76
<PAGE>


Full Cost Accounting

As noted previously,  during 2004 KeySpan disposed of its ownership  interest in
Houston   Exploration.   KeySpan  continues  to  maintain  gas  exploration  and
production  activities  through  its two  wholly-owned  subsidiaries  -  KeySpan
Exploration and Seneca-Upshur.  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.

As a result of the  disposition  of  Houston  Exploration,  during  most of 2004
KeySpan calculated the ceiling test on KeySpan  Exploration and Production's and
Seneca-Uphsur's assets independently of Houston Exploration's assets. Based on a
report furnished by an independent  reservoir engineer during the second quarter
of 2004, it was determined  that the remaining  proved  undeveloped oil reserves
held in the joint venture required a substantial investment in order to develop.
Therefore,  KeySpan and  Houston  Exploration  elected not to develop  these oil
reserves.  As a result,  in the  second  quarter  of 2004,  we  recorded a $48.2
million  non-cash   impairment   charge  to  write  down  our  wholly-owned  gas
exploration  and production  subsidiaries'  assets.  This charge was recorded in
depreciation,  depletion  and  amortization  on the  Consolidated  Statement  of
Income.

In calculating the ceiling test at December 31, 2004, 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.


                                       77
<PAGE>


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.  KeySpan's  subsidiaries  estimate
proved  reserves and future net revenues  using sales prices  estimated to be in
effect as of the date they make the reserve estimates. Natural gas prices, which
have fluctuated  widely in recent years,  affect estimated  quantities of proved
reserves and future net revenues.  Any estimates of natural gas and oil reserves
and their values are  inherently  uncertain,  including  many factors beyond our
control.  The  accuracy of any reserve  estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. In
addition,  estimates  of reserves may be revised  based upon actual  production,
results of future development and exploration activities, prevailing natural gas
and oil  prices,  operating  costs  and other  factors,  which  revision  may be
material.  Reserve  estimates  are highly  dependent  upon the  accuracy  of the
underlying  assumptions.  Actual future  production may be materially  different
from estimated  reserve  quantities and the differences  could materially affect
future amortization of natural gas and oil properties.

Accounting for Sales of Stock by a Subsidiary

KeySpan  applies the  accounting  principle of income  recognition  for gains or
losses associated with the sale of stock by its subsidiaries. As provided for in
Staff  Accounting  Bulletin  Topic 5-H ("SAB  51"),  the SEC  allows  for income
recognition  of gains or losses on subsidiary  stock  transactions  in instances
where  the  transaction  is  not  part  of a  broader  corporate  reorganization
contemplated  by the parent.  Provided  that no other capital  transactions  are
contemplated  with regard to the shares issued,  income  statement  treatment in
consolidation  for  issuance of stock by a  subsidiary  is  appropriate.  SAB 51
requires  that this  accounting  treatment,  if elected by the  parent,  must be
consistently  applied  to  all  subsidiary  stock  transactions  that  meet  the
conditions  for income  statement  recognition.  As noted  earlier,  KeySpan has
appropriately   applied  this  accounting  treatment  to  its  subsidiary  stock
transactions.

Accounting for the Sale/Leaseback Transaction and Ravenswood Master Lease

In May 2004 the Ravenswood  Expansion,  a new 250 MW combined  cycle  generating
facility at the Ravenswood Facility site began full commercial  operations.  The
entire capacity and energy produced from this plant is being sold into the NYISO
markets.

KeySpan structured a leverage-lease  financing arrangement for this facility. At
the closing of the leasing  transaction,  the new  facility  was acquired by the
lessor  from a  KeySpan  subsidiary  and  simultaneously  leased  back  to  that
subsidiary.  KeySpan  has  unconditionally  guaranteed  all  obligations  of its
subsidiary under the lease. The lease has an initial term of 36 years.

The financing  arrangement  qualifies for operating lease  accounting  treatment
under  Statement of Financial  Accounting  Standard  ("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,  an amendment of FASB  Statements  No. 13, 66, 91 and a rescission of


                                       78
<PAGE>


FASB Statement No.26 and Technical Bulletin No. 79-11." The terms and conditions
of the  financing  arrangement  are  also  in  accordance  with  the  accounting
requirements  of SFAS 13 "Accounting  for Leases," SFAS 66 "Accounting for Sales
of Real Estate," and Financial  Interpretation No. ("FIN") 46R "Consolidation of
Variable Interest Entities."

As  stated  in  SFAS  98,  sale-leaseback   accounting  shall  be  used  by  the
seller-lessee  only if the  transaction  includes  all of the  following:  (i) a
normal leaseback;  (ii) payment terms and provisions that adequately demonstrate
the buyer-lessor's  initial and continuing investment in the property; and (iii)
payment terms and provisions that transfer all of the other risks and rewards of
ownership as demonstrated by the absence of any other continuing  involvement by
the seller-lessee.

A normal leaseback is a lessee-lessor  relationship that involves the active use
of the property by the  seller-lessee in consideration  for the payment of rent.
Active use of the property  refers to the use of the  property  during the lease
term  in  the  seller-lessee's  trade  or  business.  Electric  generation  is a
significant  part of KeySpan's  normal business and since we operate the new 250
MW facility,  this criteria has been met.  Further,  since the  buyer-lessor has
paid KeySpan the full fair market value of the  facility,  as  determined  by an
independent third-party appraiser, the second criteria has also been met.

With regard to criteria (iii),  KeySpan is under no obligation to repurchase the
generating  facility,  nor does it have an option to  repurchase  the  facility.
Further,  the leasing  arrangement  does not contain a provision under which the
buyer-lessor  can compel  KeySpan  to  repurchase  the  facility.  Further,  the
buyer-lessor  assumes a significant  risk regarding return of and on the initial
capital investment.

SFAS 13 contains the following four basic criteria that, if met, would require a
lease to be classified as a capital lease: (i) the lease transfers  ownership of
the  property to the lessee by the end of the lease;  (ii) the lease  contains a
bargain  purchase  option;  (iii) the lease  term is equal to 75% or more of the
estimated  economic life of the leased  property;  and (iv) the present value at
the beginning of the lease term of the minimum lease payments  equals or exceeds
90% of the fair market value of the leased property.  The financing  arrangement
for the Ravenswood Expansion does not meet any of the above criteria.

Further,  FIN 46R  does  not  apply  to this  financing  arrangement  since  the
arrangement  meets the criteria for operating lease  accounting  treatment under
SFAS 98. More specifically the leasing  arrangement does not absorb  variability
in the fair  value in the  underlying  assets  of the lease  since  the  leasing
arrangement  does not guaranty (to the  buyer/lessor)  the residual value of the
leased  assets  and  the  arrangement   does  not  contain  an  option  for  the
seller/lessee to acquire the leased assets after the term of the lease.

Dividends

In the third quarter of 2004 KeySpan increased its dividend to an annual rate of
$1.82 per common  share  beginning  with the  quarterly  dividend  to be paid in
February  2005.  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 $1.82 level.


                                       79
<PAGE>


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, 2004 and November 30, 2004,  respectively),  the ratio of
debt  to  total   utility   capitalization   was  43%  and  44%,   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

KEDNY is  subject  to an  earnings  sharing  provision  pursuant  to which it is
required to credit  firm  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,  2004 was
13.25%.  KEDNY did not earn above its  threshold  return  level in its rate year
ended September 30, 2004. 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.

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, 2004. 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 MADTE.


                                       80
<PAGE>


Effective  November 1, 2003, the MADTE approved a $25.9 million increase in base
revenues  for the Boston Gas Company  with an allowed  return on equity of 10.2%
reflecting an equal balance of debt and equity.  On January 27, 2004,  the MADTE
issued  its  order  on  Boston   Gas   Company's   Motion   for   Recalculation,
Reconsideration  and  Clarification  that granted an additional  $1.1 million in
base revenues, for a total of $27 million. The MADTE also approved a Performance
Based Rate Plan (the "Plan") for up to ten years. On October 29, 2004, the MADTE
approved a base rate increase of $4.6 million  under the Plan.  In addition,  an
increase  of $7.9  million  in the  local  distribution  adjustment  clause  was
approved  to  recover  pension  and  other  postretirement  costs.  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.  This true-up mechanism allows for
carrying  charges on deferred  assets and  liabilities  at Boston Gas  Company's
weighted-average cost of capital.

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
laws,  accounting changes, or regulatory,  judicial, or legislative changes. 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.

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 Federal  Energy  Regulatory  Commission  ("FERC") in
accordance with the Power Supply Agreement  ("PSA") entered into between KeySpan
and LIPA in 1998. The prior FERC approved rates,  which had 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 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.  On
October 1, 2004 the FERC approved a settlement reached between KeySpan and LIPA.
Under the new Settlement Agreement,  KeySpan's rates reflect a cost of equity of
9.5% with no revenue  increase  in the first  year.  The FERC  approved  updated
operating and maintenance  expense levels and recovery of certain other costs as
agreed to by the parties.

Securities and Exchange Commission Regulation

KeySpan and certain of 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


                                       81
<PAGE>


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.

KeySpan has the authorization,  under PUHCA 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; (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 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.  At December 31, 2004, KeySpan's  consolidated common equity was
42% of its consolidated capitalization,  including commercial paper, and each of
its  utility  subsidiaries  common  equity  was at least  42% of its  respective
capitalization.

On October 1, 2004, in accordance with its PUHCA authorization,  KeySpan filed a
new  universal  shelf  registration  statement  on Form S-3 with the SEC for the
issuance from time to time of up to $3.0 billion in securities.


                                       82
<PAGE>


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.  In 2002, we
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.

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.


                                       83
<PAGE>


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 $5 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 was provided with a corresponding extension of 31
months for the MSA to the end of 2008.

LIPA is in the process of  performing a long-term  strategic  review  initiative
regarding  its  future  direction.  It  has  engaged  a  team  of  advisors  and
consultants and is conducting public hearings to develop  recommendations  to be
submitted  to the LIPA  Trustees.  Some of the  strategic  options  that LIPA is
considering  include  whether  LIPA  should  continue  its  operations  as  they
presently  exist,  fully  municipalize  or privatize,  sell some, but not all of
their  assets and become a regulator  of rates and  services.  In the near term,
LIPA must make a  determination  by May 28, 2005 as to whether it will  exercise
its option to purchase our Long Island  generating  plants pursuant to the terms
of the GPRA.  Until LIPA makes a determination on its future  direction,  we are
unable to determine what the outcome of this  strategic  review will have on our
financial condition, results of operations or cash flows. Any action that may be
taken will have to take into consideration the term of our existing contracts.

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


                                       84
<PAGE>


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 a 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 Projects

We currently sell capacity,  energy and ancillary  services  associated with the
Ravenswood Projects through a bidding process into the NYISO energy and capacity
markets.  Energy is sold 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  Projects  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.  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.

In 2004 Boston Gas Company  reached an agreement  with an insurance  carrier for
recovery of previously incurred environmental  expenditures.  Under a previously
issued MADTE order, insurance and third-party recoveries,  after deducting legal
fees, are shared  between Boston Gas and its firm gas customers.  As a result of
the  insurance  agreement,  in  September  2004 Boston Gas recorded a $5 million
benefit to operations and maintenance expense.

Also in 2004, KeySpan reached a settlement with its insurance carriers regarding
cost  recovery for expenses  incurred at a  non-utility  environmental  site and
recorded  an  $11.6  million  benefit  from the  settlement  as a  reduction  to
operations and maintenance expense.

We estimate that the  remaining  cost of our MGP related  environmental  cleanup
activities,  including costs  associated with the Ravenswood  Facility,  will be
approximately  $237.1 million and we have recorded a related  liability for such
amount.   We  have  also  recorded  an  additional   $19.7  million   liability,
representing the estimated  environmental cleanup costs related to a former coal
tar  processing  facility.  As of December 31, 2004, we have expended a total of
$138.3 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.)


                                       85
<PAGE>


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 prices,  interest rates,
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.

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 value of investments  held
change,  or long-term  interest  rates  change,  the effect will be reflected in
KeySpan's  recognition  of periodic cost of such employee  benefit plans and the
determination of contributions to the employee benefit plans.

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 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, 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 and in accordance with various
regulatory requirements.

We also have credit risk from LIPA, our largest customer,  and from other energy
and financial services  companies.  Counterparty  credit risk 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.  In
instances where counterparties'  credit quality has declined, or credit exposure
exceeds  certain  levels,  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.


                                       86
<PAGE>


Regulatory Issues and Competitive Environment

We are subject to various other risk exposures and uncertainties associated with
our gas and  electric  operations.  Set forth  below is a  description  of these
exposures.

The Gas Industry

Long Island and New York

For the last  several  years,  the NYPSC has been  monitoring  the  progress  of
competition in the energy market.  Based upon its findings of the current market
and its continued desire to move toward fully competitive markets, the NYPSC, in
August 2004,  issued a second policy  statement.  The underlying  vision remains
unchanged. The items of importance in the new policy include:

o    Elimination  of a timeframe  for the exit of  utilities  from the  merchant
     function.  Experience,  time and maturation of each  market/customer  class
     will dictate the exit of utilities.

o    Acknowledgement   that  competitive   commodity  markets  for  the  largest
     customers has occurred.  However, workable competition for the mass markets
     (i.e.  residential  and small  commercial  customers)  is taking longer and
     needs to be nurtured.

o    Future rate filings must include a plan for facilitating customer migration
     to  competitive  markets and a fully  embedded  cost of service  study that
     develops  unbundled  rates  for  the  utility's  delivery  service  and all
     potentially competitive services.

o    Utilities should avoid entering into long term capacity arrangements unless
     it is necessary for reliability and safety purposes.

o    Where  markets  are not  workably  competitive,  the NYPSC must ensure that
     rates continue to be just and reasonable,  and protect customers from price
     volatility.

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 are
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.


                                       87
<PAGE>


New England

In July 1997, the MADTE 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 MADTE in November  1998. In February 1999, the MADTE
issued its order on how  unbundling of natural gas service will  proceed.  For a
five  year  transition   period,  the  MADTE  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 MADTE 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 MADTE 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 MADTE began a proceeding to re-examine  whether the upstream capacity market
has been sufficiently competitive to allow voluntary capacity assignment.

KeySpan submitted  comments  maintaining its position that the upstream capacity
market  is not at this time  sufficiently  competitive  to remove or modify  the
MADTE's mandatory capacity assignment requirement.

Electric Industry

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
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 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 FERC has not acted on the
remand.


                                       88
<PAGE>


On June 25,  2004,  the NYISO  submitted a motion to FERC  seeking  refunds as a
result of the Decision.  KeySpan and others  submitted  statements of opposition
opposing the refunds.  On November 29, 2004,  KeySpan  filed a motion  seeking a
settlement judge be appointed to settle the case. On January 6, 2005 FERC denied
KeySpan's  request but has not yet issued a decision  on the  merits.  We cannot
predict the outcome of these proceedings or what effect, if any, the outcome may
have on our financial position, results of operations or cash flows.

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 the electric infrastructure develops and the demand for electric
power  increases  over  time 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 and generation facilities could also
cause  significant  changes to the market.  KeySpan  currently  anticipates that
approximately  1,100 MW of new capacity may be available by the end of 2006 as a
result  of  the  completion  of  in-City  generation  projects  currently  under
construction.  We cannot,  however,  be certain as to when, or if, the new power
plants  will be in  operation  or the  nature  of future  New York  City  energy
requirements or market design.

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 appeal 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.

NYISO Standard Market Design 2.0 ("SMD2")

The NYISO's revised market design and software SMD2, was implemented on February
1, 2005. It replaced the NYISO's current two step real-time market system, which
consists of the Balancing Market  Evaluation and Security  Constrained  Dispatch
applications,  with a more integrated Real Time Scheduling  system ("RTS").  RTS
uses a common computing  platform,  algorithms,  and network models for both the
real-time  commitment and real-time  dispatch  functions.  This synergy  between
commitment and dispatch functions is expected to result in improved  consistency
between advisory and real-time price schedules, as well as more efficient use of
control area resources.  SMD2 will more closely align the NYISO markets with the
FERC Standard  Market Design Notice of Proposed Rule Making,  issued on July 31,
2002.


                                       89
<PAGE>


Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

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  distribution
operations,   gas  exploration  and  production   activities  and  its  electric
generating facilities.  Our gas distribution operations utilize over-the-counter
("OTC")  natural gas and fuel oil swaps to hedge the  cash-flow  variability  of
specified   portions  of  gas  purchases  and  sales   associated  with  certain
large-volume  customers.  Seneca-Upshur  utilizes OTC natural gas swaps to hedge
cash flow  variability  associated  with  forecasted  sales of natural  gas. The
Ravenswood Projects use derivative financial  instruments to hedge the cash flow
variability  associated  with the  purchase  of a portion of natural gas and oil
that will be consumed  during the  generation  of  electricity.  The  Ravenswood
Projects  also  hedge the cash flow  variability  associated  with a portion  of
electric energy sales using OTC electricity swaps.

KeySpan  uses  standard  NYMEX  futures  prices to value gas  futures and market
quoted forward prices to value OTC swap contracts.

The following  tables set forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at December 31, 2004.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
                                               Year of         Volumes   Fixed Price        Current Price       Fair Value
     Type of Contract                          Maturity         (mmcf)        ($)                ($)              ($000)
--------------------------------------------------------------------------------------------------------------------------
           Gas
<S>                                             <C>           <C>        <C>                <C>                    <C>
Swaps/Futures - Long Natural Gas                 2005           6,595     4.95 - 7.11        6.07 - 6.28           (6,146)
                                                                                                                        -

OTC Swaps - Short Natural Gas                    2005           1,980     6.58 - 6.70        6.33 - 7.15              212
                                                 2006           1,884     6.17 - 6.29        6.07 - 7.39             (516)
                                                 2007           1,812     5.86 - 5.97        5.71 - 6.93             (362)
--------------------------------------------------------------------------------------------------------------------------
                                                               12,271                                              (6,812)
--------------------------------------------------------------------------------------------------------------------------
</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                      2005          84,000     24.65 - 34.40           33.90 - 34.75           268
                                           2006          12,000             34.40                   34.30            (1)

Swaps - Short Heating Oil                  2005          52,372             55.44           47.25 - 52.75         7,451
--------------------------------------------------------------------------------------------------------------------------
                                                        148,372                                                   7,718
--------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       90
<PAGE>

<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                           2005            1,562,400     29.95 - 103.10       33.89 - 101.69              353

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

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

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)                                                                             2004
Change in Fair Value of Derivative Hedging Instruments                                               ($000)
------------------------------------------------------------------------------------------------------------
<S>                                                                                                 <C>
Fair value of contracts at January 1, 2004                                                        $ (36,224)
Net (gains) on contracts realized                                                                      (510)
Derivative balance that has been de-consolidated (Houston Exploration)                               14,331
Increase in fair value of all open contracts                                                         23,662
------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31,                                               $   1,259
------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
-----------------------------------------------------------------------------------------------------------
                                                        Fair Value of Contracts
-----------------------------------------------------------------------------------------------------------
                                                  Maturity                      Maturity          Total
Sources of Fair Value                          In 12 Months                in 2006 and 2007      Fair Value
-----------------------------------------------------------------------------------------------------------
<S>                                                <C>                            <C>               <C>
Prices actively quoted                            $ 1,305                       $    -             $ 1,305
Local published indicies                              834                         (880)                (46)
-----------------------------------------------------------------------------------------------------------
                                                  $ 2,139                       $ (880)            $ 1,259
-----------------------------------------------------------------------------------------------------------
</TABLE>


                                       91
<PAGE>


We measure the commodity risk of our derivative hedging  instruments  (indicated
in the  above  table)  using a  sensitivity  analysis.  Based  on a  sensitivity
analysis as of December  31, 2004, a 10% increase in heating oil and natural gas
prices would  decrease the value of derivative  instruments  maturing in 2005 by
$3.3 million,  while the value of expected physical deliveries for 2005 would be
enhanced $6.4 million (net benefit to KeySpan of $3.1  million).  A 10% decrease
in heating  oil and  natural gas prices  would  enhance the value of  derivative
instruments  maturing  in 2005 by $3.3  million,  while  the  value of  expected
physical  deliveries  for 2005  would be  decreased  $6.4  million  (net cost to
KeySpan of $3.1 million).

Based on a  sensitivity  analysis as of December  31,  2004,  a 10%  increase in
electricity  and fuel prices would decrease the value of derivative  instruments
maturing in 2005 by $5.2  million,  while the value of expected  physical  power
production  for 2005 would be enhanced  $13.3 million (net benefit to KeySpan of
$8.1 million).  A 10% decrease in electricity  and fuel prices would have a $5.2
million  favorable  impact on the value of  derivative  instruments  maturing in
2005,  while the value of expected  physical power  production  would be reduced
$15.9 million (net cost to KeySpan of $10.7 million).

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  are  recorded  as a
regulatory  asset or regulatory  liability on the  Consolidated  Balance  Sheet.
Gains or losses on the  settlement  of these  contracts  are  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, 2004.

<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                    2005        10,330    5.00 - 6.00       5.00 - 7.00                -      6.07 - 6.88          (1,126)
                           2006         4,160    5.00 - 6.00       5.00 - 7.00                -      5.82 - 7.10             881

Swaps                      2005        38,400              -                 -      6.48 - 6.56      6.07 - 6.88          (9,327)
                           2006        15,340              -                 -      6.76 - 7.03      5.82 - 7.10            (820)

-----------------------------------------------------------------------------------------------------------------------------------
                                       68,230                                                                            (10,392)
-----------------------------------------------------------------------------------------------------------------------------------
</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.


                                       92
<PAGE>


Item 8. Financial Statements and Supplementary Data

                           CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                                                                                             At December 31,
(In Thousands of Dollars)                                                              2004                    2003
----------------------------------------------------------------------------------------------------------------------

ASSETS
<S>                                                                                <C>                     <C>
Current Assets
     Cash and temporary cash investments                                         $    921,973            $    203,358
     Accounts receivable                                                              788,454                 909,613
     Unbilled revenue                                                                 591,394                 446,573
     Allowance for uncollectible accounts                                             (67,796)                (75,671)
     Gas in storage, at average cost                                                  515,459                 488,521
     Material and supplies, at average cost                                           123,476                 118,912
     Other                                                                            162,739                 114,196
     Assets of discontinued operations                                                 42,923                 181,823
                                                                       -----------------------------------------------
                                                                                    3,078,622               2,387,325
                                                                       -----------------------------------------------

Investments and  Other                                                                272,893                 248,565
                                                                       -----------------------------------------------

Property
     Gas                                                                            6,871,221               6,522,251
     Electric                                                                       2,402,052               2,636,537
     Other                                                                            398,628                 407,813
     Accumulated depreciation                                                      (2,702,298)             (2,601,701)
     Gas exploration and production, at cost                                          187,053               3,088,242
     Accumulated depletion                                                            (97,475)             (1,167,427)
     Property of discontinued operations                                                8,743                   8,588
                                                                       -----------------------------------------------
                                                                                    7,067,924               8,894,303
                                                                       -----------------------------------------------

Deferred Charges
     Regulatory assets                                                                555,414                 578,383
     Goodwill and other intangible assets, net of amortization                      1,677,601               1,717,010
     Goodwill of discontinued operations                                                    -                  92,702
     Other                                                                            711,676                 721,894
                                                                       -----------------------------------------------
                                                                                    2,944,691               3,109,989
                                                                       -----------------------------------------------

Total Assets                                                                     $ 13,364,130            $ 14,640,182
                                                                       ===============================================
----------------------------------------------------------------------------------------------------------------------
</TABLE>
                See accompanying Notes to the Consolidated Financial Statements.


                                       93
<PAGE>


                           CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
                                                                                    At December 31,
(In Thousands of Dollars)                                                      2004                   2003
------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                   <C>
LIABILITIES AND CAPITALIZATION
Current Liabilities
     Current maturities of long-term debt & capital leases              $     16,103           $      1,471
     Current redemption  requirement of preferred stock                       55,300                      -
     Accounts payable and other liabilities                                  906,650              1,065,742
     Commercial paper                                                        912,246                481,900
     Dividends payable                                                        74,059                 72,289
     Taxes accrued                                                           161,629                 43,943
     Customer deposits                                                        43,262                 40,370
     Interest accrued                                                         48,822                 64,609
     Liabilities of discontinued operations                                   64,245                 81,956
                                                               ---------------------------------------------
                                                                           2,282,316              1,852,280
                                                               ---------------------------------------------

Deferred Credits and Other Liabilities
     Regulatory liabilities:
     Miscellaneous liabilities                                                73,963                104,034
     Removal costs recovered                                                 496,482                450,034
     Deferred income tax                                                   1,124,129              1,275,558
     Postretirement benefits and other reserves                              901,318                961,931
     Other                                                                   139,149                121,624
                                                               ---------------------------------------------
                                                                           2,735,041              2,913,181
                                                               ---------------------------------------------

Commitments and Contingencies (See Note 7)                                         -                      -

Capitalization
     Common stock                                                          3,501,950              3,487,645
     Retained earnings                                                       792,177                621,430
     Accumulated other comprehensive income                                  (54,336)               (59,932)
     Treasury stock                                                         (345,081)              (378,487)
                                                               ---------------------------------------------
          Total common shareholders' equity                                3,894,710              3,670,656
     Preferred stock                                                          19,700                 83,568
     Long-term debt and capital leases                                     4,418,729              5,610,948
                                                               ---------------------------------------------
Total Capitalization                                                       8,333,139              9,365,172
                                                               ---------------------------------------------

Minority Interest in Consolidated Companies                                   13,634                509,549
                                                               ---------------------------------------------
Total Liabilities and Capitalization                                    $ 13,364,130           $ 14,640,182
                                                               =============================================
------------------------------------------------------------------------------------------------------------
</TABLE>

                See accompanying Notes to the Consolidated Financial Statements.


                                       94
<PAGE>


                        CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------
                                                                                         Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts)                             2004              2003             2002
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>               <C>               <C>
Revenues
     Gas Distribution                                                      $ 4,407,292       $ 4,161,272       $ 3,163,761
     Electric Services                                                       1,738,660         1,605,973         1,645,688
     Energy Services                                                           182,406           158,908           208,624
     Gas Exploration and Production                                            279,999           501,255           357,451
     Energy Investments                                                         42,109           108,116            89,650
                                                                   --------------------------------------------------------
Total Revenues                                                               6,650,466         6,535,524         5,465,174
                                                                   --------------------------------------------------------
Operating Expenses
     Purchased gas for resale                                                2,664,492         2,495,102         1,653,273
     Fuel and purchased power                                                  540,302           414,633           395,860
     Operations and maintenance                                              1,567,022         1,622,592         1,631,297
     Depreciation, depletion and amortization                                  551,760           571,669           513,708
     Operating taxes                                                           404,212           418,236           380,527
     Impairment charges                                                         40,965                 -                 -
                                                                   --------------------------------------------------------
Total Operating Expenses                                                     5,768,753         5,522,232         4,574,665
                                                                   --------------------------------------------------------
Gain on sale of property                                                         7,021            15,123             4,730
Income from equity investments                                                  46,536            19,214            14,096
                                                                   --------------------------------------------------------
Operating Income                                                               935,270         1,047,629           909,335
                                                                   --------------------------------------------------------
Other Income and (Deductions)
     Interest charges                                                         (331,251)         (307,694)         (301,504)
     Sale of subsidiary stock                                                  388,319            13,356                 -
     Cost of debt redemption                                                   (45,879)          (24,094)                -
     Minority interest                                                         (36,797)          (63,852)          (24,918)
     Other                                                                      30,591            42,005            25,054
                                                                   --------------------------------------------------------
Total Other Income and (Deductions)                                              4,983          (340,279)         (301,368)
                                                                   --------------------------------------------------------
Income Taxes
     Current                                                                   201,909           (99,798)          (36,588)
     Deferred                                                                  123,631           381,079           266,253
                                                                   --------------------------------------------------------
Total Income Taxes                                                             325,540           281,281           229,665
                                                                   --------------------------------------------------------
Earnings from Continuing Operations                                            614,713           426,069           378,302
                                                                   --------------------------------------------------------
Discontinued Operations
    Income (loss) from operations, net of tax                                  (78,960)           (1,888)           15,692
    Loss on disposal, net of tax                                               (72,088)                -           (16,306)
                                                                   --------------------------------------------------------
    Loss from Discontinued Operations                                         (151,048)           (1,888)             (614)
                                                                   --------------------------------------------------------
Cumulative Change in Accounting Principles, net of tax                               -           (37,451)                -
                                                                   --------------------------------------------------------
Net Income                                                                     463,665           386,730           377,688
Preferred stock dividend requirements                                            5,612             5,844             5,753
                                                                   --------------------------------------------------------
Earnings for Common Stock                                                  $   458,053       $   380,886       $   371,935
                                                                   ========================================================
Basic Earnings Per Share
  Continuing Operations, less preferred stock dividends                    $      3.80       $      2.65       $      2.64
  Discontinued Operations                                                        (0.94)            (0.01)            (0.01)
  Cumulative Change in Accounting Principles                                         -             (0.23)                -
                                                                   --------------------------------------------------------
Basic Earnings Per Share                                                   $      2.86       $      2.41       $      2.63
                                                                   ========================================================
Diluted Earnings Per Share
  Continuing Operations, less preferred stock dividends                    $      3.78       $      2.63       $      2.62
  Discontinued Operations                                                        (0.94)            (0.01)            (0.01)
  Cumulative Change in Accounting Principles                                         -             (0.23)                -
                                                                   --------------------------------------------------------
Diluted Earnings Per Share                                                 $      2.84       $      2.39       $      2.61
                                                                   ========================================================
Average Common Shares Outstanding (000)                                        160,294           158,256           141,263
Average Common Shares Outstanding - Diluted (000)                              161,277           159,232           142,300
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

               See accompanying Notes to the Consolidated Financial Statements.


                                       95
<PAGE>


                      CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
                                                                                               Year Ended December 31,
(In Thousands of Dollars)                                                            2004              2003              2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>               <C>               <C>
Operating Activities
Net income                                                                        $ 463,665         $ 386,730         $ 377,688
Adjustments to reconcile net income to net
      cash provided by (used in) operating activities
    Depreciation, depletion and amortization                                        551,760           571,669           513,708
    Deferred income tax                                                             123,631           188,689            89,284
    Income from equity investments                                                  (46,536)          (18,038)          (14,096)
    Dividends from equity investments                                                14,162             2,807             3,905
    Amortization of interest rate swap                                               (2,265)           (9,861)                -
    (Gain) on interest rate swap                                                    (12,656)                -                 -
    (Gain) loss on disposal of subsidiary stock                                    (388,319)          (13,356)                -
    (Gain) on sale of assets                                                         (7,021)          (15,123)           (4,730)
    Impairment charges                                                               40,965                 -                 -
    Loss/(Income) from discontinued operations                                      151,048             1,888           (19,048)
    Cumulative change in accounting principle                                             -            37,451                 -
    Environmental reserve adjustment                                                      -           (10,459)                -
    Minority interest                                                                36,797            63,852            24,918
Changes in assets and liabilities
    Accounts receivable                                                            (234,188)           60,394          (223,983)
    Materials and supplies, fuel oil and gas in storage                             (38,967)         (198,966)           42,547
    Accounts payable and accrued expenses                                           159,513           225,756           (11,240)
    Reserve payments                                                                (37,270)          (36,486)          (23,369)
    Other                                                                           (24,250)          (13,591)           (7,921)
                                                                          ------------------------------------------------------
Net Cash Provided by Operating Activities                                           750,069         1,223,356           747,663
                                                                          ------------------------------------------------------
Investing Activities
    Construction expenditures                                                      (750,329)       (1,009,393)       (1,057,507)
    Cost of removal                                                                 (36,287)          (31,103)          (27,431)
    Other investments                                                                     -          (211,370)          (27,579)
    Net proceeds from sale of subsidiary stock                                    1,001,142           294,573           175,110
    Proceeds from sale of property                                                   20,159            15,123             4,730
    Issuance of long-term note                                                            -           (55,000)                -
                                                                          ------------------------------------------------------
Net Cash Provided by (Used in) Investing Activities                                 234,685          (997,170)         (932,677)
                                                                          ------------------------------------------------------
Financing Activities
    Treasury stock issued                                                            33,406            96,687            86,710
    Common stock issuance                                                                 -           473,573                 -
    Issuance of long-term debt                                                       49,336         1,024,553           549,260
    Payment of long-term debt                                                      (920,081)         (604,331)         (124,863)
    Net proceeds from sale/leasback transaction                                     382,049                 -                 -
    Issuance (Payment) of commercial paper                                          430,346          (433,797)         (132,753)
    Redemption of promissory notes                                                        -          (447,005)                -
    Redemption of preferred stock                                                    (8,483)          (14,293)                -
    Gain on interest rate swap                                                       12,656                 -            57,415
    Common and preferred stock dividends paid                                      (291,148)         (280,560)         (256,656)
    Other                                                                            36,187             4,989             9,629
                                                                          ------------------------------------------------------
Net Cash (Used in) Provided by Financing Activities                                (275,732)         (180,184)          188,742
                                                                          ------------------------------------------------------
Net Increase in Cash and Cash Equivalents                                         $ 709,022         $  46,002         $   3,728
Net Cash Flow from Discontinued Operations                                            9,593           (13,261)           14,166
Cash and Cash Equivalents at Beginning of Period                                    203,358           170,617           152,723
                                                                          ------------------------------------------------------
Cash and Cash Equivalents at End of Period                                        $ 921,973         $ 203,358         $ 170,617
                                                                          ======================================================
Interest Paid                                                                     $ 336,546         $ 355,136         $ 343,933
Income Tax Paid                                                                   $ 122,033         $  65,495         $  98,344
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                See accompanying Notes to the Consolidated Financial Statements.


                                       96
<PAGE>


                   CONSOLIDATED STATEMENT OF RETAINED EARNINGS

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                                                                                   Year Ended December 31,
(In Thousands of Dollars)                                                   2004             2003             2002
---------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>                <C>              <C>
Balance at Beginning of Period                                          $  621,430       $  522,835       $  452,206
Net Income for Period                                                      463,665          386,730          377,688
---------------------------------------------------------------------------------------------------------------------
                                                                         1,085,095          909,565          829,894
Deductions:
Cash dividends declared on common stock                                    287,306          282,291          252,175
Cash dividends declared on preferred stock                                   5,612            5,844            5,753
MEDS Equity Units                                                                -                -           49,131
---------------------------------------------------------------------------------------------------------------------
Balance at End of Period                                                $  792,177       $  621,430       $  522,835
---------------------------------------------------------------------------------------------------------------------
</TABLE>



                 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
                                                                                                Year Ended December 31,
(In Thousands of Dollars)                                                               2004             2003             2002
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>              <C>              <C>
Net Income                                                                           $ 463,665        $ 386,730        $ 377,688
---------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income, net of tax
Net losses (gains) on derivative instruments                                              (332)          23,042          (17,033)
Deconsolidation of certain subsidiaries                                                  9,315                -                -
Foreign currency translation adjustments                                               (21,536)          28,696            9,759
Unrealized gains (losses) on marketable securities                                       7,111            8,480          (10,019)
Premium on derivative instrument                                                         3,437           (3,437)               -
Accrued unfunded pension obligation                                                     (7,818)           8,380          (55,768)
Unrealized (losses) gains on derivative financial instruments                           15,419          (25,379)         (39,845)
---------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax                                            5,596           39,782         (112,906)
---------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income                                                                 $ 469,261        $ 426,512        $ 264,782
---------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Net losses (gains) on derivative instruments                                              (178)          12,407           (9,172)
Deconsolidation of certain subsidiaries                                                  5,016                -                -
Foreign currency translation adjustments                                               (11,596)          15,451            5,255
Unrealized gains (losses) on marketable securities                                       3,830            4,568           (5,395)
Accrued unfunded pension obligation                                                     (4,210)           4,513          (30,029)
Premium on derivative instrument                                                         1,851           (1,851)               -
Unrealized (losses) gains on derivative financial instruments                            8,240          (13,666)         (21,454)
---------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense                                                          $   2,953        $  21,422        $ (60,795)
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                See accompanying Notes to the Consolidated Financial Statements.


                                       97
<PAGE>


                    CONSOLIDATED STATEMENT OF CAPITALIZATION

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                         December 31,                           December 31,
(In Thousands of Dollars)                                       2004                     2003              2004             2003
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>                   <C>                 <C>              <C>
Common Shareholders' Equity                                             Shares Issued
Common stock, $0.01 par value                                  172,737,654           172,737,654       $     1,727      $     1,727
Premium on capital stock                                                                                 3,500,223        3,485,918
Retained earnings                                                                                          792,177          621,430
Other comprehensive income                                                                                 (54,336)         (59,932)
Treasury stock                                                  11,919,343            13,073,219          (345,081)        (378,487)
------------------------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity                              160,818,311           159,664,435         3,894,710        3,670,656
------------------------------------------------------------------------------------------------------------------------------------

Preferred Stock - 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                  -            8,568
Less: current redemption requirements                             (553,000)                   -            (55,300)               -
------------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required                                                                 19,700           83,568
------------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt                                       Interest Rate               Maturity
------------------------------------------------------------------------------------------------------------------------------------
Notes
Medium term notes                                      4.65% - 9.75%             2005 - 2033             2,485,000        3,185,000
Senior secured notes                                    6.08%- 8.8%              2008 - 2013                     -           96,425
Senior subordinated notes                                   7.0%                     2013                        -          175,000
------------------------------------------------------------------------------------------------------------------------------------
Total Notes                                                                                              2,485,000        3,456,425
------------------------------------------------------------------------------------------------------------------------------------
Gas Facilities Revenue Bonds                             Variable                   2020                   125,000          125,000
                                                       5.50% - 6.95%             2020 - 2026               515,500          523,500
------------------------------------------------------------------------------------------------------------------------------------
Total Gas Facilities Revenue Bonds                                                                         640,500          648,500
------------------------------------------------------------------------------------------------------------------------------------

Promissory Notes to LIPA

Pollution control revenue bonds                            5.15%                    2016                   108,020          108,022
Electric facilities revenue bonds                          5.30%                 2023 - 2025                47,400           47,400
------------------------------------------------------------------------------------------------------------------------------------
Total Promissory Notes to LIPA                                                                             155,420          155,422
------------------------------------------------------------------------------------------------------------------------------------

MEDS Equity Units                                          8.75%                    2005                   460,000          460,000
Industrial Development Bonds                               5.25%                    2027                   128,275          128,275
First Mortgage Bonds                                   6.08% - 8.80%             2008 - 2028                95,000          153,186
Authority Financing Notes                                Variable                2027 - 2028                66,005           66,005
Other Subsidiary Debt                                                                                            -          145,128
Ravenswood Master Lease & Capital Leases                                         2005 - 2022               424,083          425,262
------------------------------------------------------------------------------------------------------------------------------------
Subtotal                                                                                                 4,454,283        5,638,203
Unamortized interest rate hedge and debt discount                                                          (55,185)         (69,243)
Derivative impact on debt                                                                                   35,734           43,459
Less: current maturities                                                                                    16,103            1,471
------------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt                                                                                     4,418,729        5,610,948
------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                                                                   $ 8,333,139      $ 9,365,172
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                See accompanying Notes to the Consolidated Financial Statements.


                                       98
<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,  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 2.6 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  electric  power,
electric  transmission  and  distribution  services,  billing and other customer
services for  approximately  1.1 million  electric  customers of the Long Island
Power Authority ("LIPA").

Our other  subsidiaries are involved in gas production;  gas storage;  liquefied
natural gas storage; wholesale and retail electric marketing; appliance service;
a  minimum  amount of fiber  optic  services;  and  engineering  and  consulting
services.  We also invest in, and  participate in the development of natural gas
pipelines;  electric generation, and other energy-related projects. (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


                                       99
<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  intercompany  transactions  have been
eliminated.   Certain  reclassifications  were  made  to  conform  prior  period
financial  statements to current period financial  statement  presentation.  For
December  31,  2004,  2003  and  2002 we have  reclassified  the  operations  of
KeySpan's  mechanical  contracting  subsidiaries,  which are part of the  Energy
Services segment,  as discontinued  operations on the Consolidated  Statement of
Income,  Consolidated  Balance Sheet and  Consolidated  Statement of Cash Flows.
(See Note 11 "Energy Services - Discontinued  Operations" for additional details
regarding these operations.) In addition,  for December 31, 2003 we reclassified
the minimum  pension  liability  for Boston Gas Company from  accumulated  other
comprehensive income to regulatory assets. (See Note 4 "Postretirement Benefits"
for additional information.)

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 ("MADTE").  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.


                                       100
<PAGE>


In separate merger related orders issued by the MADTE, 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, 2004 and
December 31, 2003.


<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
                                                                                    December 31,
(In Thousands of Dollars)                                                     2004                2003
---------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                 <C>
Regulatory Assets
Regulatory tax asset                                                       $  53,149           $  60,700
Property taxes                                                                45,235              51,390
Environmental costs                                                          272,545             296,888
Postretirement benefits                                                      110,603             106,682
Costs associated with the KeySpan/LILCO transaction                           39,091              50,585
Derivative financial instruments                                              27,293               6,909
Other                                                                          7,498               5,229
---------------------------------------------------------------------------------------------------------
Total Regulatory Assets                                                    $ 555,414           $ 578,383
Miscellaneous Regulatory Liabilities                                         (73,963)           (104,034)
---------------------------------------------------------------------------------------------------------
Net Regulatory Assets                                                        481,451             474,349

Removal Costs Recovered                                                     (496,482)           (450,034)
---------------------------------------------------------------------------------------------------------
                                                                           $ (15,031)          $  24,315
---------------------------------------------------------------------------------------------------------
</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 $37.7  million and $53.4  million at December 31, 2004 and December
31, 2003,  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.

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


                                       101
<PAGE>


and  liabilities  could  result.  If we were  unable  to  continue  to apply the
provisions of SFAS 71 for any of our rate regulated subsidiaries, we would apply
the  provisions  of  SFAS  101,  "Regulated  Enterprises  -  Accounting  for the
Discontinuation  of  Application  of FASB  Statement  71." We estimate  that the
write-off  of  all  net   regulatory   assets  at  December  31,  2004,   before
consideration of removal costs recovered, could result in a charge to net income
of  $313  million  or  $1.95  per  share,   which  would  be  classified  as  an
extraordinary  item. In 2003, KeySpan implemented SFAS 143 "Accounting for Asset
Retirement  Obligations"  and  reclassified  the cost of  removal  reserve  from
accumulated  depreciation to regulatory liability.  In management's opinion, the
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.
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 weather related  derivative  instruments  from time to time. (See
Note  8  "Hedging,   Derivative  Financial  Instruments  and  Fair  Values"  for
additional information on these derivatives.)

Electric Services: Electric revenues are primarily derived from: (i) billings to
LIPA for management of LIPA's  transmission  and  distribution  ("T&D")  system,
electric  generation,  and procurement of fuel, and (ii):  subsidiaries that own
lease and operate  the 2,200  megawatt  ("MW")  Ravenswood  electric  generation
facility  ("Ravenswood  Facility")  and the recently  completed  250 MW combined
cycle generating  facility located at the Ravenswood  facility site ("Ravenswood
Expansion").


                                       102
<PAGE>


LIPA Agreements:

KeySpan manages the day-to-day operations,  maintenance and capital improvements
of the T&D  system  under a  Management  Service  Agreement  ("MSA").  KeySpan's
billings to LIPA are based on certain  agreed upon terms.  In addition,  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 KeySpan 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,  KeySpan 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.

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 its
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  KeySpan
earns 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 $5  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.

The Electric  Services  segment also conducts retail marketing of electricity to
commercial customers. Energy sales made by our electric marketing subsidiary are
recorded upon delivery of the related commodity.

LIPA is in the process of  performing a long-term  strategic  review  initiative
regarding  its future  direction  which may impact the above  mentioned  service
agreements.  (See Note 7  "Contractual  Obligations,  Financial  Guarantees  and
Contingencies" for further information regarding LIPA's strategic review.)


                                       103
<PAGE>


Ravenswood Facilities:

In addition,  electric  revenues are derived  from our  investment  in the 2,200
megawatt ("MW") Ravenswood electric generation facility ("Ravenswood Facility"),
(which  KeySpan  acquired  in June  1999).  KeySpan  has an  arrangement  with a
variable  interest  entity  through  which we lease a portion of the  Ravenswood
Facility.  Further,  in May  2004  KeySpan  completed  construction  of a 250 MW
combined  cycle  generating  facility  located at the  Ravenswood  facility site
("Ravenswood Expansion").  To finance the Ravenswood Expansion,  KeySpan entered
into a  leveraged  lease  financing  arrangement.  Collectively  the  Ravenswood
Facility  and  Ravenswood  Expansion  will  be  referred  to as  the  Ravenswood
Projects.  (See  Note  7  "Contractual  Obligations,  Financial  Guarantees  and
Contingencies" for a description of the financing  arrangements  associated with
the  Ravenswood  Projects.)  We  realize  revenues  from our  investment  in the
Ravenswood  Projects 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.  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.

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.


                                       104
<PAGE>


KeySpan has recently sold its mechanical contracting  companies,  the operations
of which have been  reflected in  discontinued  operations  on the  Consolidated
Statement of Income and on the Consolidated  Balance Sheet and Statement of Cash
Flows.  (See Note 11 "Energy Services - Discontinued  Operations" for additional
details on the mechanical contracting companies.)

Energy service and maintenance  revenues  associated  with small  commercial and
residential  appliances are recognized as earned or over the life of the service
contract,  as  appropriate.  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
$28.5 million and $23.8 million as of December 31, 2004,  and December 31, 2003,
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.  During
2004  KeySpan  disposed  of its  interest  in The  Houston  Exploration  Company
("Houston Exploration"), an independent natural gas and oil exploration company.
KeySpan continues to maintain, on a significantly smaller scale, gas exploration
and production  activities.  (See Note 2 "Business Segments" for a discussion on
the disposition of Houston  Exploration and KeySpan's  remaining gas exploration
activities.)

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 year ended  December 31, 2004 ranged
from  1.54% to 6.47%.  Capitalized  interest  for  2004,  2003 and 2002 was $7.4
million, $13.5 million and $19.7 million, respectively.

Depreciation  is  provided on a  straight-line  basis in amounts  equivalent  to
composite rates on average depreciable property. The cost of property retired 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, 2004 and 2003,
KeySpan had costs  recovered in excess of costs  incurred  totaling $496 million
and $450  million,  respectively.  These  amounts are  reflected as a regulatory
liability.


                                       105
<PAGE>


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,
                                          2004            2003           2002
-------------------------------------------------------------------------------
Electric                                  3.87%           3.81%          3.88%
Gas                                       3.55%           3.37%          3.44%
-------------------------------------------------------------------------------

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


We also had $398.6 million of other property at December 31, 2004, consisting of
assets held primarily by our Corporate Service  subsidiary of $293.7 million and
$89.9 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.

KeySpan  capitalizes  costs incurred in connection  with its projects to develop
and build  new  energy  facilities  after a project  has been  determined  to be
probable.

F.  Gas Exploration and Production Property - Depletion

As noted previously and discussed in more detail in Note 2 "Business  Segments",
during 2004, KeySpan disposed of its ownership interest in Houston  Exploration.
KeySpan continues to maintain gas exploration and production  activities through
its two  wholly-owned  subsidiaries - KeySpan  Exploration and  Production,  LLC
("KeySpan  Exploration"),  which is  engaged  in a joint  venture  with  Houston
Exploration,  and Seneca-Upshur Petroleum, Inc.  ("Seneca-Upshur").  At December
31, 2004, these subsidiaries had net exploration and production  property in the
amount of $89.6  million.  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  plus  asset
retirement  obligations  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  is made as to the existence of proved
reserves.  Properties  are depleted and charged to operations  using the unit of
production method using proved reserve quantities.

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.


                                       106
<PAGE>


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 ceiling
test calculations.

As a result of the  disposition  of  Houston  Exploration,  during  most of 2004
KeySpan calculated the ceiling test on KeySpan  Exploration and Production's and
Seneca-Uphsur's assets independently of Houston Exploration's assets. Based on a
report furnished by an independent  reservoir engineer during the second quarter
of 2004, it was determined  that the remaining  proved  undeveloped oil reserves
held in the joint venture required a substantial investment in order to develop.
Therefore,  KeySpan and  Houston  Exploration  elected not to develop  these oil
reserves.  As a result,  in the  second  quarter  of 2004,  we  recorded a $48.2
million  non-cash   impairment   charge  to  write  down  our  wholly-owned  gas
exploration  and production  subsidiaries'  assets.  This charge was recorded in
depreciation,  depletion  and  amortization  on the  Consolidated  Statement  of
Income.

As of December 31, 2004, we estimated,  using an average wellhead price adjusted
for derivative  instruments of $6.45 per MCF, that our capitalized costs did not
exceed the ceiling  test  limitation.  As of December  31, 2003 and December 31,
2002,  we  estimated,  using a  wellhead  prices  of $5.79  and  $4.35  per MCF,
respectively,  that our  capitalized  costs  did not  exceed  the  ceiling  test
limitation for those periods.

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 low,
there are significant  downward revisions in our estimated proved reserves or we
have unsuccessful drilling results.

Houston Exploration  capitalized 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, 2004,  2003 and 2002,
capitalized   interest  was  $3.4  million,   $7.3  million  and  $8.0  million,
respectively.

G.  Goodwill and Other Intangible Assets

The balance of goodwill and other intangible assets was $1.7 billion at December
31, 2004 and $1.8  billion at December  31,  2003,  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.


                                       107
<PAGE>


The table below summarizes the goodwill and other intangible assets balance for
each segment at December 31, 2004 and 2003:

------------------------------------------------------------------------------
(In Thousands of Dollars)                                 December 31,
------------------------------------------------------------------------------
Operating Segment                                    2004              2003

Gas Distribution                                 $1,436,917        $1,436,917
Energy Services                                      65,782           172,874
Energy Investments and other                        174,902           199,921
------------------------------------------------------------------------------
                                                 $1,677,601        $1,809,712
------------------------------------------------------------------------------


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  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 is recorded as an
operating expense. During 2002, KeySpan conducted an impairment analysis for all
its reporting units and determined that no consolidated impairment existed.

In 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 this  valuation,  management  determined  that the fair  value of the  assets
adequately exceeded their carrying value and no impairment charge was necessary.

The Energy  Services  segment  has  experienced  significantly  lower  operating
profits  and cash flows  than  originally  projected.  As  previously  reported,
management had reviewed the operating  performance of this segment. At a meeting
held on November 2, 2004, KeySpan's Board of Directors authorized  management to
begin the  process  of  disposing  of a  significant  portion  of its  ownership
interests in certain companies within the Energy Services segment - specifically
those companies  engaged in mechanical  contracting  activities.  In January and
February of 2005, KeySpan sold these mechanical contracting investments.

In  anticipation  of these sales and in connection  with the  preparation of the
third quarter and fourth  quarter  financial  statements,  KeySpan  conducted an
evaluation  of the  carrying  value of  these  investments,  including  recorded
goodwill.  Further,  we evaluated the carrying  value of goodwill for the entire
Energy Services segment.


                                       108
<PAGE>


As a result of this evaluation, KeySpan recorded a non-cash goodwill impairment
charge of $108.3 million ($80.3 million after tax, or $0.50 per share) in 2004.
This charge was recorded as follows: (i) $14.4 million as an operating expense
on the Consolidated Statement of Income reflecting the write-down of goodwill on
Energy Services segment's continuing operations; and (ii) $93.9 million as
discontinued operations reflecting the impairment on the mechanical contracting
companies. (See Note 11 "Energy Services - Discontinued Operations" for further
details on the discontinued companies.)

In  addition  to the  goodwill  evaluation  conducted  for the  Energy  Services
segment,  KeySpan  conducted  evaluations  of the  goodwill  recorded in the Gas
Distribution and Energy Investments  segments.  Based on KeySpan's evaluation of
the fair value of the Gas  Distribution  unit,  KeySpan  concluded that the fair
value of the Gas Distribution unit exceeded the carrying value and no impairment
charge was necessary.

KeySpan  has  entered  into an  agreement  to sell its 50%  interest  in Premier
Transmission Limited ("PTL"), a gas pipeline from southwest Scotland to Northern
Ireland,  before the end of the second quarter of 2005. In the fourth quarter of
2004 KeySpan  recorded a pre-tax non-cash  impairment  charge of $26.5 million -
$18.8 million  after-tax or $0.12 per share,  reflecting the difference  between
the  anticipated  cash  proceeds  from the sale of PTL  compared to its carrying
value.  The  impairment  charge was recorded as a reduction  to  goodwill.  This
investment  is accounted for under the equity method of accounting in the Energy
Investments segment.

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


                                       109
<PAGE>


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.

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.


                                       110
<PAGE>


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 current
investments are publicly traded.

J.  Income and Excise Tax

Upon implementation of SFAS 109,  "Accounting for Income Taxes",  certain of our
regulated  subsidiaries  recorded  a  regulatory  asset and a net  deferred  tax
liability  for the  cumulative  effect of  providing  deferred  income  taxes on
certain  differences  between the financial statement carrying amounts of assets
and liabilities, and their respective tax bases. This regulatory asset continues
to be amortized over the lives of the individual assets and liabilities to which
it relates.  Additionally,  investment tax credits which were available prior to
the Tax Reform Act of 1986, were deferred and generally amortized as a reduction
of income tax over the estimated lives of the related property.

We report our  collections  and payments of excise  taxes on a gross basis.  Gas
distribution  revenues  include the collection of excise taxes,  while operating
taxes include the related  expense.  For the years ended December 31, 2004, 2003
and 2002,  excise taxes  collected and paid were $73.3  million,  $90.5 million,
$83.1 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, 2004 and 2003, 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  anti-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.


                                       111
<PAGE>


At December 31, 2004 all options  outstanding  to purchase  KeySpan common stock
were used in the  calculation  of  diluted  EPS.  In 2003 and 2002 we had 85,676
shares of convertible preferred stock outstanding that could have been converted
into 221,153 shares of common stock. These shares were redeemed in 2004.

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)                                      2004             2003              2002
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>              <C>               <C>
Earnings for common stock                                                             $ 458,053        $ 380,886         $ 371,935
Houston Exploration dilution                                                                  -             (269)             (471)
Preferred stock dividend                                                                      -              514               531
-----------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted                                                  $ 458,053        $ 381,131         $ 371,995
-----------------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000)                                               160,294          158,256           141,263
Add dilutive securities:
Options                                                                                     983              755               809
Convertible preferred stock                                                                   -              221               228
-----------------------------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution                           161,277          159,232           142,300
-----------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share                                                              $    2.86        $    2.41         $    2.63
-----------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share                                                            $    2.84        $    2.39         $    2.61
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


N.  Stock Options and Other Stock Based Compensation

Stock options are issued 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 five to ten
years.  Up to  approximately  21 million  shares  have been  authorized  for the
issuance of options and approximately 5.2 million of these shares were remaining
at December 31, 2004.  Moreover,  under a separate plan, Houston Exploration had
issued and  outstanding  approximately  2.5 million stock options to key Houston
Exploration  employees.  KeySpan and Houston Exploration adopted the prospective
method of transition in accordance  with SFAS 148  "Accounting  for  Stock-Based
Compensation - Transition and Disclosure." Accordingly, compensation expense has
been recognized by employing the fair value  recognition  provisions of SFAS 123
"Accounting  for Stock-Based  Compensation"  for grants awarded after January 1,
2003.

KeySpan  continues  to apply APB Opinion  25,  "Accounting  for Stock  Issued to
Employees," and related  Interpretations  in accounting for grants awarded prior
to January 1, 2003.  Prior to the  disposition of Houston  Exploration,  Houston
Exploration  also  applied  APB  Opinion  25,  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


                                       112
<PAGE>


determined based on the fair value at the grant dates for awards under the plans
consistent  with SFAS 123,  our net income  and  earnings  per share  would have
decreased to the pro-forma amounts indicated below:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
                                                                                           Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts)                                 2004             2003               2002
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>               <C>                <C>
Earnings available for common stock:
As reported                                                                     $ 458,053         $ 380,886          $ 371,935
     Add: recorded stock-based compensation expense, net of tax                     9,109             3,650                221
     Deduct: total stock-based compensation expense, net of tax                   (12,356)           (9,358)            (7,547)
-------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings                                                              $ 454,806         $ 375,178          $ 364,609
-------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
     Basic - as reported                                                        $    2.86         $    2.41          $    2.63
     Basic - pro-forma                                                          $    2.84         $    2.37          $    2.58

     Diluted - as reported                                                      $    2.84         $    2.39          $    2.61
     Diluted - pro-forma                                                        $    2.82         $    2.36          $    2.56
-------------------------------------------------------------------------------------------------------------------------------
</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,
                                                            2004                 2003                2002
------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                    <C>                 <C>
Fair value of grants issued                             $   5.47              $  4.26              $  3.42
Dividend yield                                              4.74%                5.49%                5.36%
Expected volatility                                        23.48%               24.26%               22.47%
Risk free rate                                              3.22%                3.16%                4.94%
Expected lives                                          6.5 years              6 years             10 years
Exercise price                                          $   37.54             $  32.40             $  32.66
------------------------------------------------------------------------------------------------------------
</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,
                                                   2004                             2003                             2002
------------------------------------------------------------------------------------------------------------------------------------
                                                          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       10,320,743       $ 31.39          9,524,900        $ 30.74         7,796,162       $ 29.67
Granted during the year                   1,602,850       $ 37.54          1,650,450        $ 32.40         2,796,310       $ 32.66
Exercised                                (1,150,464)      $ 28.05           (664,902)       $ 23.64          (506,794)      $ 24.42
Forfeited                                  (232,183)      $ 35.18           (189,705)       $ 34.63          (560,778)      $ 30.99
------------------------------------------------------------------------------------------------------------------------------------
Outstanding at end of period             10,540,946       $ 32.61         10,320,743        $ 31.39         9,524,900       $ 30.74
------------------------------------------------------------------------------------------------------------------------------------
Exercisable at end of period              5,523,259       $ 30.39          5,365,545        $ 28.76         4,105,999       $ 27.69
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       113
<PAGE>


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                        Options                                                 Options
Remaining           Outstanding at       Weighted Average     Range of       Exercisable at      Weighted Average      Range of
Contractual Life    December 31, 2004     Exercise Price    Exercise Price   December 31, 2004     Exercise Price    Exercise Price
------------------------------------------------------------------------------------------------------------------------------------
<S>                  <C>                      <C>           <C>               <C>                     <C>           <C>
 1 years                   1,800             $ 27.00       $     27.00             1,800             $ 27.00       $     27.00
 2 years                 167,086             $ 30.41       $ 20.57 - 30.50       167,086             $ 30.41       $ 20.57 - 30.50
 3 years                 236,410             $ 32.54       $ 19.15 - 32.63       236,410             $ 32.54       $ 19.15 - 32.63
 4 years               1,006,679             $ 27.92       $ 24.73 - 29.38     1,006,679             $ 27.92       $ 24.73 - 29.38
 5 years                 541,755             $ 26.98       $ 21.99 - 27.06       541,754             $ 26.98       $ 21.99 - 27.06
 6 years               1,272,983             $ 22.72       $ 22.50 - 32.76     1,272,983             $ 22.72       $ 22.50 - 32.76
 7 years               1,917,889             $ 39.50       $     39.50         1,229,789             $ 39.50       $     39.50
 8 years               2,340,508             $ 32.66       $     32.66           834,509             $ 32.66       $     32.66
 9 years               1,492,792             $ 32.40       $     32.40           232,249             $ 32.40       $     32.40
 10 years              1,563,044             $ 37.54       $     37.54                 -             $ 37.54       $     37.54
------------------------------------------------------------------------------------------------------------------------------------
                      10,540,946                                               5,523,259
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

Since 2003,  KeySpan  provides  long-term  incentive  compensation  for officers
consisting of 50% stock options and 50% performance  shares.  Performance shares
are awarded based upon the attainment of overall corporate performance goals and
better aligns incentive compensation with overall corporate performance.

O.  Recent Accounting Pronouncements

In May 2004, the Financial Accounting Standards Board ("FASB") issued FASB Staff
Position ("FSP") 106-2  "Accounting and Disclosure  Requirements  Related to the
Medicare  Prescription  Drug,  Improvement and  Modernization Act of 2003." This
guidance  superseded  FSP  106-1  issued  in  January  2004  and  clarifies  the
accounting and disclosure requirements for employers with postretirement benefit
plans  that  have  been or will  be  affected  by the  passage  of the  Medicare
Prescription Drug Improvement and Modernization Act of 2003 ("the Act"). The Act
introduced  two new features to Medicare  that an employer  needs to consider in
measuring its obligation  and net periodic  postretirement  benefit  costs.  The
effective date for the new  requirements  was the first interim or annual period
beginning after June 15, 2004.

KeySpan's  retiree health benefit plan  currently  includes a prescription  drug
benefit  that  is  provided  to  retired  employees.   KeySpan  implemented  the
requirements  of FSP 106-2 in  September  2004 and  determined  that the savings
associated  with  the  Act  reduced  KeySpan's  retiree  health  care  costs  by
approximately  $10  million in 2004.  However,  KEDLI and Boston Gas Company are
subject to certain  deferral  accounting  requirements  mandated by the New York
State Public Service  Commission  ("NYPSC") and the Massachusetts  Department of
Telecommunications  and Energy  ("MADTE"),  respectively  for pension  costs and
other  postretirement  benefit costs.  Further,  in accordance  with our service
agreements with LIPA,  variations between pension costs and other postretirement
benefit  costs  incurred by KeySpan  compared to those costs  recovered  through
rates  charged to LIPA are deferred  subject to recovery from or refund to LIPA.
As a result of these various  requirements,  approximately $7 million of savings
attributable  to the  implementation  of FSP 106-2 and the Act was  deferred and
used to offset  increases in overall pension and  postretirement  benefit costs,
with the  remaining  approximately  $3 million  recorded as a reduction  to 2004
postretirement  expense.  The  implementation  of FSP  106-2  and the Act had no
immediate impact on KeySpan's cash flow.


                                       114
<PAGE>


In  January  2005,  the  Department  of Health  and Human  Services/Centers  for
Medicare and Medicaid  Services (CMS) released final  regulations with regard to
the implementation of the major provisions of the Medicare Act. We are currently
evaluating  the final  regulations,  and at this time we  cannot  determine  the
impact,  if any,  these  regulations  may  have on our  results  of  operations,
financial position or cash flows.

In December 2004 the FASB issued SFAS 123 (revised 2004) "Share-Based  Payment."
This  Statement  focuses  primarily on accounting for  transactions  in which an
entity obtains  employee  services in  share-based  payment  transactions.  This
Statement  revises  certain  provisions of SFAS 123  "Accounting for Stock-Based
Compensation"  and  supersedes  APB Opinion 25  "Accounting  for Stock Issued to
Employees."  The  fair-value-based  method in this  Statement  is similar to the
fair-value-based  method  in  Statement  123  in  most  respects.  However,  the
following are key differences  between the two: Entities are required to measure
liabilities  incurred to employees in share based payment  transactions  at fair
value as compared to using the intrinsic  method  allowed under  Statement  123.
Entities  are  required  to  estimate  the number of  instruments  for which the
requisite  service is expected to be  rendered,  as compared to  accounting  for
forfeitures as they occur under Statement 123. Incremental compensation cost for
a  modification  of the  terms  or  conditions  of an award  are  also  measured
differently under this Statement  compared to Statement 123. This Statement also
clarifies and expands  Statement 123's guidance in several areas.  The effective
date of this Statement is the beginning of the first interim or annual reporting
period that begins after June 15, 2005. As noted  earlier,  KeySpan  adopted the
prospective  method of transition for stock options 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 for grants  awarded after January 1,
2003.  KeySpan is currently  reviewing the  requirements of this Statement,  and
believes that  implementation  of this Statement will not have a material impact
on its results of  operations  or  financial  position and no effect on its cash
flows.

P. Impact of Cumulative Effect of Change in Accounting Principles

As noted previously,  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 Financial Accounting
Standards Board ("FASB")  Interpretation  No. 46 ("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,  in 2003 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.)

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  2003
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.)


                                       115
<PAGE>


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)                           2004                      2003               2002
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>                    <C>                <C>
Earnings for common stock                                                      N/A                  $ 380,886          $ 371,935
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
     Less: SFAS 143 Accretion expense, net of taxes                                                         -             (1,135)
     Less:FIN 46  Depreciation expense, net of taxes                                                   (9,538)            (8,024)
     Add: SFAS 143 Costs of removal expense, net of taxes                                                   -                471
---------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings                                                                                  $ 408,799          $ 363,247
---------------------------------------------------------------------------------------------------------------------------------

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

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

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

     Diluted - as reported                                                                          $    2.39          $    2.61
     Diluted - pro-forma                                                                            $    2.57          $    2.55
---------------------------------------------------------------------------------------------------------------------------------
</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>
----------------------------------------------------------------------------------------------------
                                                                                 December 31,
(In Thousands of Dollars)                                                  2004               2003
----------------------------------------------------------------------------------------------------
<S>                                                                    <C>                 <C>
Foreign currency translation adjustments                              $   4,987           $  26,523
Unrealized (losses) on marketable securities                               (419)             (7,530)
Premium on derivative instrument                                              -              (3,437)
Accrued unfunded pension obligation                                     (59,760)            (51,942)
Unrealized (losses) on derivative financial instruments                     856             (23,546)
----------------------------------------------------------------------------------------------------
Accumulated other comprehensive income                                $ (54,336)          $ (59,932)
----------------------------------------------------------------------------------------------------
</TABLE>


                                       116
<PAGE>


Note 2. Business Segments

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

The Gas Distribution segment consists of our six gas distribution  subsidiaries.
KEDNY  provides  gas  distribution  services to  customers  in the New York City
Boroughs  of  Brooklyn,  Staten  Island and a portion of the  Borough of Queens.
KEDLI  provides  gas  distribution  services  to  customers  in the Long  Island
counties of Nassau and Suffolk and the Rockaway  Peninsula of Queens County. The
remaining gas distribution  subsidiaries,  collectively doing business as KEDNE,
provide  gas  distribution   service  to  customers  in  Massachusetts  and  New
Hampshire.

The  Electric  Services  segment  consists  of  subsidiaries  that:  operate the
electric  transmission  and  distribution  system owned by LIPA; own and provide
capacity to and produce energy for LIPA from our generating  facilities  located
on Long  Island;  and  manage  fuel  supplies  for LIPA to fuel our Long  Island
generating facilities.  These services are provided in accordance with long-term
service  contracts having remaining terms that range from four to nine years and
power  purchase  agreements  having  remaining  terms that range from nine to 23
years.  The Electric  Services  segment also includes  subsidiaries  that own or
lease and operate the 2,200 megawatt  Ravenswood  electric  generation  facility
("Ravenswood  Facility")  located in Queens,  New York,  as well as the recently
completed  250  MW  combined-cycle  electric  generating  unit  located  at  the
Ravenswood site ("Ravenswood  Expansion").  Collectively the Ravenswood Facility
and Ravenswood  Expansion are referred to as the "Ravenswood  Projects".  All of
the energy,  capacity and ancillary services related to the Ravenswood  Projects
are  sold  to  the  NYISO  energy  markets.   To  finance  the  purchase  and/or
construction   of  the  Ravenswood   Projects,   KeySpan  entered  into  leasing
arrangement  for each  facility.  The Electric  Services  segment also  conducts
retail   marketing  of  electricity  to  commercial   customers.   (See  Note  7
"Contractual  Obligations,  Financial  Guarantees and Contingencies" for further
details on the leasing arrangements.)

The Energy Services segment includes  companies that provide  energy-related and
fiber optic  services to customers  located  primarily  within the  Northeastern
United States,  with concentrations in the New York City and Boston metropolitan
areas 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   operation  and
maintenance,  design,  engineering  and  consulting  services to commercial  and
industrial customers.  For December 31, 2004, 2003 and 2002 we have reclassified
the  operations  of Energy  Services'  mechanical  contracting  subsidiaries  as
discontinued  operations on the Consolidated  Statement of Income,  Consolidated
Balance  Sheet  and  Consolidated  Statement  of Cash  Flows.  In 2004,  KeySpan
recorded a non-cash goodwill  impairment charge of $108.3 million ($80.3 million
after  tax,  or $0.50 per  share)  associated  with its  mechanical  contracting
operations and certain remaining  operations.  In addition, an impairment charge
of $100.3 million ($72.1 million  after-tax or $.45 per share) was also recorded
to  reduce  the  carrying  value  of the  remaining  assets  of  the  mechanical
contracting companies.  (See Note 11 "Energy Services - Discontinued Operations"
for additional details regarding these charges.)


                                       117
<PAGE>


The Energy  Investments  segment  consists of our gas exploration and production
investments, as well as certain other domestic and international  energy-related
investments. In June 2004, KeySpan exchanged 10.8 million shares of common stock
of The Houston  Exploration  Company  ("Houston  Exploration"),  an  independent
natural gas and oil exploration  company, for 100% of the stock of Seneca Upshur
Petroleum,  Inc.  ("Seneca-Upshur"),  previously  a wholly owned  subsidiary  of
Houston   Exploration.   This  transaction   reduced  our  interest  in  Houston
Exploration  from  55% to  approximately  23.5%.  As part  of this  transaction,
Houston  Exploration  retired  4.6  million of its common  shares and issued 6.8
million  new  shares  in a  public  offering.  Based  on  Houston  Exploration's
announced offering price of $48.00 per share, Seneca-Upshur's shares were valued
at the equivalent of $449 million, or $41.57 per share.  Seneca-Upshur's  assets
consisted of West Virginia gas producing  properties valued at $60 million,  and
$389 million in cash.  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, this transaction resulted in a gain
to KeySpan of $150.1  million which was reflected in other income and deductions
on the  Consolidated  Statement  of  Income.  Effective  June 1,  2004,  Houston
Exploration's  earnings and our ownership  interest in Houston  Exploration were
accounted for on the equity basis of accounting.  The deconsolidation of Houston
Exploration  required the recognition of certain deferred taxes on our remaining
investment resulting in a net deferred tax expense of $44.1 million.  Therefore,
the net gain on the share  exchange  less the  deferred tax  provision  was $106
million, or $0.66 per share.

In  November  2004,  KeySpan  sold  its  remaining  23.5%  interest  in  Houston
Exploration  (6.6 million  shares) and received cash  proceeds of  approximately
$369  million.  KeySpan  recorded  a  pre-tax  gain of $179.6  million  which is
reflected  in other income and  (deductions)  on the  Consolidated  Statement of
Income. The after-tax gain was $116.8 million or $0.73 per share.

Houston Exploration's  revenues,  which are reflected in KeySpan's  Consolidated
Statement of Income, were $266.4 million,  $494.7 million, and $345.4 million in
fiscal years 2004, 2003 and 2002, respectively.  Houston Exploration's operating
income,  including  KeySpan's  share of equity  earnings,  were $138.5  million,
$199.1  million  and  $109.3  million  in  fiscal  years  2004,  2003 and  2002,
respectively.

Our gas  exploration  and  production  activities  now include our  wholly-owned
subsidiaries Seneca-Upshur and KeySpan Exploration and Production, LLC ("KeySpan
Exploration and  Production"),  which is engaged in a joint venture with Houston
Exploration.  It should be noted  that in the second  quarter  of 2004,  KeySpan
recorded a $48.2  million  non-cash  impairment  charge to recognize the reduced
valuation of proved  reserves.  (See Note 1 "Summary of  Significant  Accounting
Policies"  Item F "Gas  Exploration  and  Production  Property - Depletion"  for
further information on this charge.)

Asset  transactions  regarding our investment in Houston  Exploration  were also
recorded in 2003. 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
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.


                                       118
<PAGE>


For most of 2004,  subsidiaries in this segment also held an ownership  interest
in  certain  midstream  natural  gas assets in Western  Canada  through  KeySpan
Canada.  These assets  included 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.  At the beginning of 2004, KeySpan
held a 60.9% ownership  interest in KeySpan Canada.  In April 2004,  KeySpan and
KeySpan  Facilities  Income Fund (the "Fund"),  an open-ended  income fund trust
which previously owned the other 39.1% interest in KeySpan Canada, consummated a
transaction whereby the Fund sold 15.617 million units of the Fund at a price of
CDN$12.60 per unit for gross total proceeds of approximately  CDN$196.8 million.
The  proceeds  of the  offering  were used by the Fund to acquire an  additional
35.91%  interest in KeySpan  Canada from  KeySpan.  We received  net proceeds of
approximately  CDN$186.3  million  (or  approximately  US$135  million),   after
commissions and expenses.  The Fund's ownership in KeySpan Canada increased from
39.1% to 75%, and KeySpan's  ownership of KeySpan Canada decreased from 60.9% to
25%. KeySpan recorded a gain of $22.8 million ($10.1 million after-tax, or $0.06
per  share) on this  transaction.  Effective  April 1,  2004,  KeySpan  Canada's
earnings and our ownership  interest in KeySpan Canada had been accounted for on
the equity basis of accounting.

In July 2004, the Fund issued an additional 10.7 million units,  the proceeds of
which  were used to fund the  acquisition  of the  midstream  assets of  Chevron
Canada  Midstream  Inc.  This  transaction  had the effect of  further  diluting
KeySpan's ownership of KeySpan Canada to 17.4%. KeySpan continued to account for
its  investment  in KeySpan  Canada on the equity basis of  accounting  since it
still exercised significant influence over this entity.

In December 2004, KeySpan sold its remaining 17.4% interest in KeySpan Canada to
the Fund and received net proceeds of approximately  $119 million and recorded a
pre-tax gain of approximately $35.8 million,  which is reflected in other income
and (deductions) on the Consolidated Statement of Income. The after-tax gain was
approximately $24.7 million, or $0.15 per share.

KeySpan  Canada's  revenues,  which  are  reflected  in  KeySpan's  Consolidated
Statement of Income,  were $25.2 million,  $90.3  million,  and $74.9 million in
fiscal  years 2004,  2003 and 2002,  respectively.  KeySpan  Canada's  operating
income,  including KeySpan's share of equity earnings, were $16.5 million, $28.2
million and $24.5 million in fiscal years 2004, 2003 and 2002, respectively.

Asset transactions regarding our investment in KeySpan Canada were also recorded
in 2003.  In 2003, we sold a portion of our interest in KeySpan  Canada  through
the Fund. The Fund acquired a 39.1% ownership interest in KeySpan Canada through
an indirect  subsidiary,  and then  issued 17 million  trust units to the public
through an initial  public  offering.  Each trust unit  represented a beneficial
interest in the Fund and was  registered on the Toronto Stock Exchange under the
symbol KEY.UN. Additionally, we sold our 20% interest in Taylor NGL LP that owns


                                       119
<PAGE>


and  operates  two  extraction  plants 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.

This segment is also  engaged in pipeline  development  activities.  KeySpan and
Duke  Energy  Corporation  each own a 50%  interest in  Islander  East  Pipeline
Company,  LLC  ("Islander  East").  Islander  East was  created  to  pursue  the
authorization  and  construction  of an interstate  pipeline  from  Connecticut,
across Long Island Sound,  to a terminus  near  Shoreham,  Long Island.  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.  Further,  in August 2004, KeySpan
acquired a 21% interest in the Millennium  Pipeline project which will transport
up to 500,000 DTH of natural gas a day from Corning to Ramapo,  New York,  where
it will connect to an existing pipeline.

Additionally,  subsidiaries  in this segment  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 the KeySpan LNG facility
in Providence,  Rhode Island, a 600,000 barrel liquefied natural gas storage and
receiving  facility.  Further,  this  segment has a 50%  interest in the Premier
Transmission Pipeline ("PTL") in Northern Ireland. On February 25, 2005, KeySpan
entered into a Share Sale and Purchase Agreement with BG Energy Holdings Limited
and Premier Transmission Financing Public Limited Company ("PTFPL"), pursuant to
which all of the  outstanding  shares of PTL are to be purchased by PTFPL. It is
expected  that the sale of our 50%  interest  in PTL will  result in proceeds of
approximately  $42.5 million and that the closing of this transaction will occur
before the end of the second  quarter  of 2005.  In the fourth  quarter of 2004,
KeySpan recorded a pre-tax non-cash  impairment  charge of $26.5 million - $18.8
million  after-tax or $0.12 per share,  reflecting  the  difference  between the
anticipated  cash proceeds from the sale of PTL compared to its carrying  value.
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.  The after-tax gain was
$16.0 million, or $0.10 per share.

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.  As noted  earlier,  the  mechanical
contracting   subsidiaries,   included  in  Energy  Services,  are  reported  as
discontinued  operations in 2004, 2003 and 2002.  Further,  due to the July 2002
sale  of  Midland  Enterprises  LLC,  an  inland  marine  barge  business,  this
subsidiary  is  reported  as  discontinued  operations  for  2002.  (See Note 9,
"Discontinued Operations" for more information on the sale of Midland). Further,
to better  align the  subsidiaries  within our  segments,  we  reclassified  the
operating results of our electric marketing  subsidiary from the Energy Services
segment to the  Electric  Services  segment in the first  quarter of 2004.  As a
result we reclassified  the financial  results for all periods of 2003 and 2002.


                                       120
<PAGE>


The revised reportable segment information is as follows:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                     Gas          Electric     Energy     Gas Exploration      Other       Elimi-       Consoli-
(In Thousands of Dollars)        Distribution     Services    Services    and Production    Investments    nations        dated
----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
<S>                               <C>            <C>          <C>           <C>           <C>              <C>        <C>
Unaffiliated revenue               4,407,292      1,738,660    182,406       279,999          42,109             -      6,650,466
Intersegment revenue                       -              -     11,515             -           4,879       (16,394)             -
Depreciation, depletion and
 amortization                        276,487         88,252      7,478       156,981           7,306        15,256        551,760
Sales of property                          -          2,000          -             -           5,021             -          7,021
Income from equity investments             -              -          -        20,757          25,779             -         46,536
Operating income                     579,563        289,781    (48,302)       94,455          10,238         9,535        935,270
Interest income                        2,215          9,926         40         3,504           2,989        (9,202)         9,472
Interest charges                     176,799         72,945     19,399         3,487           3,882        54,739        331,251
Total assets                       8,908,786      2,144,275    246,609         3,379         697,924     1,363,157     13,364,130
Equity method investments                  -              -          -             -         107,059             -        107,059
Construction expenditures            414,522        150,320     13,693       146,543          13,682        11,569        750,329
----------------------------------------------------------------------------------------------------------------------------------
</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 $1.7 billion for the year
ended  December  31,  2004  represents  approximately  25% of  our  consolidated
revenues during that period.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                     Gas          Electric     Energy     Gas Exploration      Other       Elimi-       Consoli-
(In Thousands of Dollars)        Distribution     Services    Services    and Production    Investments    nations        dated
------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
<S>                              <C>             <C>           <C>        <C>              <C>           <C>           <C>
Unaffiliated revenue              4,161,272       1,605,973     158,908      501,255        108,116              -       6,535,524
Intersegment revenue                      -             101       7,467            -          5,008        (12,576)              -
Depreciation, depletion and
 amortization                       259,934          67,161       7,146      204,102         19,046         14,280         571,669
Sales of property                    15,123               -           -            -              -              -          15,123
Income from equity investments            -               -           -            -         19,106            108          19,214
Operating income                    574,254         269,874     (32,963)     197,209         41,345         (2,090)      1,047,629
Interest income                       1,194           4,628       1,070            -          1,002         (2,235)          5,659
Interest charges                    203,733          44,158      15,794        8,504          7,541         27,964         307,694
Total assets                      8,457,469       2,511,125     407,485    1,530,875        915,383        817,845      14,640,182
Equity method investments                 -               -           -            -         97,018              -          97,018
Construction expenditures           419,549         256,498       6,982      295,943         18,154         12,267       1,009,393
-----------------------------------------------------------------------------------------------------------------------------------
</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.

                                       121
<PAGE>


<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                                     Gas          Electric     Energy     Gas Exploration      Other       Elimi-       Consoli-
(In Thousands of Dollars)        Distribution     Services    Services    and Production    Investments    nations        dated
-----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
<S>                              <C>              <C>          <C>         <C>             <C>            <C>          <C>
Unaffiliated revenue              3,163,761        1,645,688    208,624       357,451        89,650              -       5,465,174
Intersegment revenue                      -              101          -             -         1,128         (1,229)              -
Depreciation, depletion and
 amortization                       237,186           61,377      8,487       176,925        14,573         15,160         513,708
Sales of property                       903            1,479          -             -         2,348              -           4,730
Income from equity investments            -                -          -             -        13,992            104          14,096
Operating income                    531,134          289,694    (45,581)      110,259        32,335         (8,506)        909,335
Interest income                       2,020            1,834      1,248             -           238         (3,768)          1,572
Interest charges                    215,140           58,788     18,187         7,303         6,858         (4,772)        301,504
Total assets                      7,783,011        1,848,767    423,746     1,187,425       974,409        762,692      12,980,050
Equity method investments                 -                -          -             -       130,815              -         130,815
Construction expenditures           412,433          348,147      8,133       241,477        31,243         16,074       1,057,507
-----------------------------------------------------------------------------------------------------------------------------------
</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  25% of  our  consolidated
revenues during that period.


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 asset 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:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
                                                 Year Ended December 31,
(In Thousands of Dollars)              2004                2003              2002
------------------------------------------------------------------------------------
<S>                                  <C>                <C>                <C>
Current income tax                  $ 201,909          $ (99,798)         $ (36,588)
Deferred income tax                   123,631            381,079            266,253
------------------------------------------------------------------------------------
Total income tax                    $ 325,540          $ 281,281          $ 229,665
------------------------------------------------------------------------------------
</TABLE>



                                       122
<PAGE>


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:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                                   December 31,
(In Thousands of Dollars)                                 2004                       2003
---------------------------------------------------------------------------------------------------
<S>                                                 <C>                        <C>
Reserves not currently deductible                  $      4,598              $      34,342
New York corporation income tax                         (19,010)                   (56,188)
Property related differences                         (1,080,033)                (1,049,237)
Regulatory tax asset                                    (21,433)                   (21,222)
Property taxes                                          (99,106)                   (98,089)
Other items - net                                        90,855                    (85,164)
---------------------------------------------------------------------------------------------------
Net deferred tax liability                         $ (1,124,129)             $  (1,275,558)
---------------------------------------------------------------------------------------------------
</TABLE>

During the year ended December 31, 2002, an adjustment to deferred  income taxes
of $177.7  million  was  recorded  to reflect a decrease in the tax basis of the
assets acquired at the time of the  KeySpan/LILCO  combination.  This adjustment
resulted  from a revised  valuation  study.  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  LILCO's  tax  returns  for the tax years  ending
December 31, 1996 through March 31, 1999 and  KeySpan's  and The Brooklyn  Union
Gas  Company's  tax returns for the tax years ending  September 30, 1997 through
December 31, 1998, pertaining to the KeySpan/LILCO combination, as well as other
return years. The primary issue raised in the conduct of the examination relates
to the valuation of the transferred assets in the KeySpan/LILCO combination.  At
this time, we cannot predict the outcome of the ongoing audit. However,  KeySpan
has evaluated the potential  outcomes  which may result based on the progress of
the  examination  to date and believes that it has  adequately  provided for any
potential tax which may be assessed.

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

The table below sets forth the reasons for such differences:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------
                                                                 Year Ended December 31,
(In Thousands of Dollars)                                     2004                    2003                    2002
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                         <C>                     <C>                      <C>
Computed at the statutory rate                            $  329,089            $    247,573            $     212,788
Adjustments related to:
Tax credits                                                   (2,150)                      -                   (1,026)
Removal costs                                                   (584)                 (6,592)                  (4,787)
Accrual to return adjustments                                (10,718)                    549                   (9,539)
Sale of Houston Exploration                                   (8,445)                      -                        -
Sale of Canada                                               (14,067)                      -                        -
Minority interest in Houston Exploration                      12,879                  19,969                    9,490
State income tax, net of federal benefit                      24,833                  28,462                   42,125
Other items - net                                             (5,297)                 (8,680)                 (19,386)
-----------------------------------------------------------------------------------------------------------------------------
Total income tax                                         $   325,540           $     281,281            $     229,665
-----------------------------------------------------------------------------------------------------------------------------
Effective income tax rate (1)                                    35%                     40%                      38%
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Reflects both federal as well as state income taxes.


                                       123
<PAGE>


In December 2004, the FASB issued Staff Position ("FSP") No. 109-2,  "Accounting
and Disclosure Guidance for the Foreign Earnings  Repatriation  Provision within
the American  Jobs Creation Act of 2004." The American Jobs Creation Act of 2004
(the  "Act"),  signed  into law on  October  22,  2004,  provides  for a special
one-time  tax  deduction,  or dividend  received  deduction  ("DRD"),  of 85% of
qualifying  foreign earnings that are repatriated in either a company's last tax
year that began  before  the  enactment  date or the first tax year that  begins
during the one-year  period  beginning on the enactment date. FSP 109-2 provides
entities  additional time to assess the effect of repatriating  foreign earnings
under the Act for purposes of applying SFAS 109,  "Accounting for Income Taxes,"
which  typically  requires  the  effect of a new tax law to be  required  in the
period of  enactment.  KeySpan will elect,  if  applicable,  to apply the DRD to
qualifying  dividends  of  foreign  earnings  repatriated  in 2005.  KeySpan  is
awaiting  further  clarifying  guidance  from the U.S.  Treasury  Department  on
certain  provisions of the Act. Once this guidance is received,  KeySpan expects
to complete its  evaluation  of the effects of the Act during 2005.  Because the
evaluation  is ongoing,  it is not yet practical to estimate a range of possible
income tax effects of potential repatriations.

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  typically   based  on  age,  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 MADTE,  respectively
for pension costs and other postretirement benefit costs.

The calculation of net periodic pension cost is as follows:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------
                                                                                Year Ended December 31,
(In Thousands of Dollars)                                            2004                2003                2002
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>                 <C>                  <C>
Service cost, benefits earned during the period                 $   52,908           $  47,531            $  42,423
Interest cost on projected benefit obligation                      144,241             138,270              132,424
Expected return on plan assets                                    (158,267)           (130,556)            (157,958)
Net amortization and deferral                                       63,307              66,949               (4,247)
-----------------------------------------------------------------------------------------------------------------------------
Total pension cost                                              $  102,189           $ 122,194            $  12,642
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                       124
<PAGE>


The following  table sets forth the pension plans' funded status at December 31,
2004 and December 31, 2003.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
                                                                                           Year Ended December 31,
(In Thousands of Dollars)                                                                2004                  2003
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>                    <C>
Change in benefit obligation:
Benefit obligation at beginning of period                                          $ (2,343,196)         $  (2,080,193)
Service cost                                                                             (52,908)              (47,531)
Interest cost                                                                          (144,241)              (138,270)
Amendments                                                                               (2,316)                (3,079)
Actuarial loss                                                                         (114,597)              (192,617)
Benefits paid                                                                           137,142                118,494
-----------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                                                  (2,520,116)            (2,343,196)
-----------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period                                      1,855,239              1,544,518
Actual return on plan assets                                                            164,225                335,757
Employer contribution                                                                   146,565                 93,458
Benefits paid                                                                          (137,142)              (118,494)
-----------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                                            2,028,887              1,855,239
-----------------------------------------------------------------------------------------------------------------------
Funded status                                                                          (491,229)              (487,957)
Unrecognized net loss from past experience different from that
 assumed and from changes in assumptions                                                612,145                557,204
Unrecognized prior service cost                                                          57,653                 64,925
-----------------------------------------------------------------------------------------------------------------------
Net prepaid pension cost reflected on consolidated balance sheet                   $    178,569          $     134,172
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------
                                                                   Year Ended December 31,
                                                             2004             2003             2002
-----------------------------------------------------------------------------------------------------
<S>                                                         <C>              <C>              <C>
Assumptions:
Obligation discount                                          6.00%            6.25%            6.75%
Asset return                                                 8.50%            8.50%            8.50%
Average annual increase in compensation                      4.00%            4.00%            4.00%
-----------------------------------------------------------------------------------------------------
</TABLE>


                                       125
<PAGE>


The following benefit payments, which reflect expected future service, as
appropriate, are expected to be paid in the years indicated:


------------------------------------------------------------------
(In Thousands of Dollars)                   Pension Benefits
------------------------------------------------------------------
        2005                                    $ 127,287
        2006                                    $ 128,708
        2007                                    $ 131,000
        2008                                    $ 134,934
        2009                                    $ 139,048
        Years 2010- 2014                        $ 796,286
------------------------------------------------------------------


Unfunded  Pension  Obligation:  At  December  31, 2004 the  accumulated  benefit
obligation was in excess of pension assets. As prescribed by SFAS 87 "Employers'
Accounting for  Pensions,"  KeySpan had a $255.9  million  minimum  liability at
December 31, 2004,  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  accumulated  other
comprehensive income on the Consolidated Balance Sheet.

Therefore,  at year-end,  we had a long-term asset in deferred  charges other of
$49.7 million,  representing the amount of unrecognized prior service cost and a
debit  to  other  comprehensive  income  of  $91.9  million,  or  $59.8  million
after-tax.  The remaining amount of $114.3 million was recorded as a contractual
receivable from LIPA of $100.1 million and a regulatory  asset of $14.2 million,
representing  the amounts that could be  recovered  from LIPA and the Boston Gas
ratepayer in accordance  with our service and rate  agreements if the underlying
assumptions  giving rise to this minimum liability were realized and recorded as
pension expense.  The Boston Gas Company has received approval from the MADTE to
defer as a regulatory asset the amount of its current and future minimum pension
liability  to  reflect  its  ability  to  recover  in rates its  actual  pension
liability.

At December  31, 2004 the  projected  benefit  obligation,  accumulated  benefit
obligation and value of assets for plans with accumulated benefit obligations in
excess  of plan  assets  were $ 1.3  billion,  $1.2  billion  and $881  million,
respectively.

At December 31, 2003, the accumulated  benefit  obligation was also in excess of
pension assets.  As a result,  we had a minimum  liability of $244.4 million,  a
long-term asset in deferred charges other of $55.3 million, and a debit to other
comprehensive income of $79.9 million, or $51.9 million after-tax. The remaining
amount of $109.2 million was recorded as a contractual  receivable  from LIPA of
$95.8 million and a regulatory asset of $13.4 million.


                                       126
<PAGE>


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

At the end of each 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 Contributory Medical and prescription drug programs
and non-contributory life insurance programs 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)                                         2004          2003           2002
-----------------------------------------------------------------------------------------------------
<S>                                                            <C>           <C>            <C>
Service cost, benefits earned during the period                $ 19,656      $ 18,825       $ 16,566
Interest cost on accumulated
   postretirement benefit obligation                             70,225        69,803         65,486
Expected return on plan assets                                  (33,892)      (27,530)       (36,839)
Net amortization and deferral                                    40,981        35,815         17,527
-----------------------------------------------------------------------------------------------------
Other postretirement cost                                      $ 96,970      $ 96,913       $ 62,740
-----------------------------------------------------------------------------------------------------
</TABLE>









                                       127
<PAGE>


The following table sets forth the plans' funded status at December 31, 2004 and
December 31, 2003.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
                                                                                                      Year Ended December 31,
(In Thousands of Dollars)                                                                            2004                2003
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>                 <C>
Change in benefit obligation:
Benefit obligation at beginning of period                                                       $(1,267,624)        $(1,056,944)
Impact due to new Medicare subsidy                                                                   60,578                   -
Service cost                                                                                        (19,656)            (18,825)
Interest cost                                                                                       (70,225)            (69,803)
Plan participants' contributions                                                                     (1,933)             (1,757)
Amendments                                                                                           27,392              35,458
Actuarial (loss)                                                                                   (119,914)           (209,446)
Benefits paid                                                                                        54,644              53,693
--------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                                                              (1,336,738)         (1,267,624)
--------------------------------------------------------------------------------------------------------------------------------
Change in plan  assets:
Fair value of plan assets at beginning of period                                                    438,434             361,166
Actual return on plan assets                                                                         38,765              85,625
Employer contribution                                                                                39,510              43,578
Plan participants' contributions                                                                      1,932               1,757
Benefits paid                                                                                       (54,644)            (53,693)
--------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                                                          463,997             438,433
--------------------------------------------------------------------------------------------------------------------------------
Funded status                                                                                      (872,741)           (829,191)
Unrecognized net loss from past experience different from that assumed
 and from changes in assumptions                                                                    576,856             573,277
Unrecognized prior service cost                                                                    (106,523)            (89,034)
--------------------------------------------------------------------------------------------------------------------------------
Accrued postretirement cost reflected on consolidated balance sheet                             $  (402,408)        $  (344,948)
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
                                                                                         Year Ended December 31,
                                                                                2004              2003              2002
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>               <C>               <C>
Assumptions:
Obligation discount                                                             6.00%             6.25%             6.75%
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 11.0%  grading  down to 5.0%  over  five  years,  and 5.0%  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, 2004 by
$158.0 million and the net periodic  health care expense by $12.6 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, 2004 by
$138.4 million and the net periodic health care expense by $10.7 million.

The reduction in the APBO for the subsidy related to the benefits  attributed to
past service is $60.6 million.  The effect of the subsidy on the  measurement of
net  periodic  postretirement  benefit  cost  for the  current  period  is $10.1
million.  That effect includes  amortization of the actuarial experience gain in


                                       128
<PAGE>


the  reduction in the APBO,  for the subsidy  related to benefits  attributed to
past service,  as a component of the net amortization called for by paragraph 59
of SFAS 106 of $5.8 million.  The reduction in the current  period  service cost
due to the subsidy is $0.5 million.  The resulting reduction in interest cost on
the APBO as a result of the subsidy is $3.8 million.

At December 31, 2004,  KeySpan had a contractual  receivable from LIPA of $256.9
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.


The following  benefit  payments,  which reflect  expected  future  service,  as
appropriate, are expected to be paid in the years indicated:


-------------------------------------------------------------------------------
                                                                 Subsidiary
                                       Gross Benefit             Receipts
(In Thousands of Dollars)                 Payments               Expected**
-------------------------------------------------------------------------------

        2005                             $  63,563               $      -
        2006                             $  67,257               $  3,530
        2007                             $  70,605               $  3,843
        2008                             $  73,417               $  4,145
        2009                             $  76,368               $  4,408
        Years 2010- 2014                 $ 418,664               $ 24,631
--------------------------------------------------------------------------------
**  Rebates  are based on  calendar  year in which  prescription  drug costs are
incurred. Actual receipt of rebates may occur in the following year.


Pension/Other  Post Retirement  Benefit Plan Assets:  Keyspan's weighted average
asset allocations at December 31, 2004 and 2003, by asset category, for both the
pension and other postretirement benefit plans are as follows:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
                                                        Pension                            OPEB
Asset Category                                   2004             2003             2004             2003
--------------------------------------------------------------------------------------------------------
<S>                                             <C>              <C>               <C>            <C>
Equity securities                                 64%              61%               72%            68%
Debt securities                                   28%              31%               23%            26%
Cash and equivalents                               3%               2%                0%             2%
Venture capital                                    5%               6%                5%             4%
--------------------------------------------------------------------------------------------------------
Total                                            100%             100%              100%           100%
--------------------------------------------------------------------------------------------------------
</TABLE>


                                       129
<PAGE>


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 and fixed income  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  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 performance of equity investments over long-term periods.

Cash Contributions: In 2005, KeySpan is expected to contribute approximately $82
million  to its  pension  plans  and  approximately  $36  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, 2004, 2003 and 2002, we recorded an expense of $14.7 million, $11.2
million, and $11.2 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,  2004,  we had 11.9 million
shares,  or  approximately  $345  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  2004,  we issued 1.2 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.

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.


                                       130
<PAGE>


At December  31,  2004 we had  553,000  shares  outstanding  of 7.07%  Mandatory
Redeemable  Preferred  Stock  Series B par value $100  redeemable  in 2005;  and
197,000 shares outstanding of 7.17% Mandatory  Redeemable Preferred Stock Series
C par value $100 redeemable in 2008.

In July 2004,  KeySpan  redeemed 83,268 shares of preferred stock 6.00% Series A
par value  $100  that were  previously  issued in a private  placement.  KeySpan
redeemed  these shares at a 2% premium and incurred a cash  expenditure  of $8.5
million.

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, 2004, each of which is guaranteed by KeySpan.

KeySpan had $2.66 billion of medium and long term notes  outstanding at December
31,  2003 of  which  $1.65  billion  of these  notes  were  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. During 2004,  KeySpan redeemed the $700
million,  7.25% Notes due 2005  series.  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 $48.9  million
reflecting  call  premiums of $40.9 million and the write-off of $8.0 million of
previously  deferred  financing  costs. The call premiums are reflected in other
income and  (deductions)  while the write-off of previously  deferred  financing
costs have been reflected in interest expense on the  Consolidated  Statement of
Income.  Therefore,  at  December  31, 2004  KeySpan has $1.96  billion of notes
remaining  having  interest  rates  ranging  from 4.65% to 9.75% that  mature in
2005-2033.

On January 14, 2005,  KeySpan  redeemed  $500  million  6.15% Series due 2006 of
outstanding debt.  KeySpan incurred $20.9 million in call premiums and wrote-off
$1.0 million of previously deferred financing costs.

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. During 2004, KEDNY
retired $8.0 million of its outstanding Gas Facilities  Revenue Bonds. The funds
used to retire  this debt were drawn  from a special  deposit  defeasance  trust
previously established by KEDNY.  Therefore, at December 31, 2004 $640.5 million
of Gas  Facilities  Revenue Bonds remain  outstanding.  The interest rate on the
variable  rate series due December 1, 2020 is reset weekly and ranged from 0.64%
to 1.65% during the year ended  December  31,  2004,  at which time the rate was
1.65%.


                                       131
<PAGE>


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. At December 31, 2004, $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, 2004,  KeySpan was in
compliance with this requirement.

MEDS Equity Units: At December 31, 2004, 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 9.2 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,  13 million  shares will be issued.  If the average
closing  price  over this time frame is  greater  than or equal to $42.36,  10.9
million  shares will be issued.  The number of shares  issued at a price between
$35.30  and $42.36  will be between  10.9  million  and 13 million  based upon a
sliding scale.

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.

Industrial   Development  Revenue  Bonds:  At  December  31,  2004  KeySpan  had
outstanding  $128.3 million of tax-exempt  bonds with a 5.25% coupon maturing in
June 2027.  Fifty-three million dollars of these Industrial  Development Revenue
Bonds were issued in its behalf 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 in its behalf by the Suffolk  County
Industrial  Development  Authority  for the Port  Jefferson  electric-generation
peaking  plant.   KeySpan  has   guaranteed  all  payment   obligations  of  our
subsidiaries with regard to these bonds.


                                       132
<PAGE>


First  Mortgage  Bonds:  Colonial  Gas Company  ("Colonial"),  Essex Gas Company
("Essex"), ENI and their respective subsidiaries, had outstanding $153.2 million
of first mortgage  bonds at December 31, 2003.  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.   During  2004,   KeySpan  redeemed  $58.2  million  of  these  bonds,
representing all previously outstanding bonds of Essex and ENI. KeySpan incurred
call premiums of $13.6 million  associated with this  redemption,  of which $5.0
million  was  expensed.  The  remaining  amount of the call  premiums  have been
deferred for future regulatory recovery. Further, KeySpan wrote-off $0.2 million
of previously deferred financing costs. The call premiums are reflected in other
income and  (deductions)  while the write-off of previously  deferred  financing
costs have been reflected in interest expense on the  Consolidated  Statement of
Income.  Therefore,  at December 31, 2004, $95.0 million of first mortgage bonds
remain  outstanding  having  interest  rates  ranging  from  6.08% to 8.80%  and
maturities that range from 2008-2028.

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,  2004,  $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 2004 ranged from 0.75% to 1.50%,
through December 31, 2004, at which time the rate was 1.45%.

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  0.88% to 2.01% from  January 1, 2004  through
December 31, 2004, at which time the rate was 2.01%.

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,  unaffiliated
financing  entity  that  acquired  a portion  of the  facility,  or three  steam
generating units,  directly from Consolidated  Edison and leased it to a KeySpan
subsidiary.  The variable  interest  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 are  substantially  equal to the monthly interest
expense on the debt securities.

We have  classified  the Master Lease as $412.3 million of long-term debt on the
Consolidated Balance Sheet based on our current status as primary beneficiary as
defined in Financial  Accounting  Standards  Board  Interpretation  No. 46 ("FIN
46"), "Consolidation of Variable Interest Entities, an Interpretation of ARB No.
51." Further,  we have an asset on the Consolidated  Balance Sheet for an amount


                                       133
<PAGE>


substantially  equal  to the  fair  market  value of the  leased  assets  at the
inception of the lease,  less  depreciation  since that date,  or  approximately
$339.6 million.  Under the terms of our two credit facilities,  the Master Lease
is considered  debt in the ratio of  debt-to-total  capitalization.  (See Note 7
"Contractual Obligations, Financial Guarantees and Contingencies" for additional
information  regarding the leasing arrangement  associated with the Master Lease
Agreement.)

Registered  Securities:  In 2004,  in accordance  with its PUHCA  authorization,
KeySpan filed a new universal shelf registration  statement on Form S-3 with the
SEC for the issuance from time to time of up to $3.0 billion in securities. This
authorization  provides KeySpan with the necessary flexibility to finance future
capital requirements for the next several years.

Commercial Paper and Revolving Credit Agreements:  In 2004, KeySpan restructured
its credit  facilities.  We entered into a new $640 million five year  revolving
credit  facility to replace the $450 million,  364 day facility which expired in
June 2004.  We also  amended our existing  three year $850 million  facility due
June 2006 to reduce commitments  thereunder by $190 million to $660 million. The
two credit  facilities  total $1.3 billion and are each syndicated among sixteen
banks. These facilities  continue to support KeySpan's  commercial paper program
for working capital needs.

The fees for these  facilities  are  subject to a  ratings-based  grid,  with an
annual fee of 0.08% on the new  five-year  facility  and 0.125% on the  existing
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 in the five-year facility are based on
the Eurodollar  rate plus a margin of 0.40% for loans up to 33% of the facility,
and an additional  0.125% for loans over 33% of the facility.  In the three-year
facility  Eurodollar  loans  are based on the  Eurodollar  rate plus a margin of
0.625% for loans up to 33% of the facility,  and an additional  0.125% for loans
over 33% of the facility.  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%.
Competitive  bid loans are based on bid results  requested  by KeySpan  from the
lenders.  We do not anticipate  borrowing against these facilities;  however, if
the credit rating on our commercial paper program were to be downgraded,  it may
be necessary to do so.

The facilities  contain 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% until the
expiration of the existing three-year facility in 2006, at which time it will be
lowered to 62%.  Violation of this covenant  could result in the  termination of
the facilities and the required  repayment of amounts  borrowed  thereunder,  as
well as possible cross defaults under other debt agreements.

Under  the  terms  of  the  credit   facility,   the  calculation  of  KeySpan's
debt-to-total  capitalization  ratio reflects 80% equity  treatment for the MEDS
Equity Units.  At December 31, 2004,  consolidated  indebtedness,  as calculated
under   the  terms  of  the   credit   facility,   was  53.4%  of   consolidated


                                       134
<PAGE>


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.

At December 31,  2004,  we had cash and  temporary  cash  investments  of $922.0
million.  During 2004, we borrowed  $430.3  million of commercial  paper and, at
December 31, 2004,  $912.2  million of  commercial  paper was  outstanding  at a
weighted average annualized  interest rate of 2.4%. We had the ability to borrow
up to an additional  $387.8  million at December 31, 2004,  under the commercial
paper program.

As a result of the sale of Houston  Exploration and KeySpan  Canada,  the credit
facilities of these previous  subsidiaries  are no longer reflected on KeySpan's
Consolidated Balance Sheet. However, the borrowings and repayments through these
credit  facilities are reflected on KeySpan's  Consolidated  Cash Flow Statement
for the period that these subsidiaries were consolidated. During the time period
that Houston  Exploration's  results were  consolidated with KeySpan's (the five
months ended May 31, 2004)  Houston  Exploration  borrowed $49 million under its
credit  facility and repaid $136  million.  KeySpan  Canada repaid $17.7 million
under its  facility  during the first  three  months of 2004 (the time period in
which its results were consolidated with KeySpan's).

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 6.07%.

Debt Maturity:  The following table reflects the maturity  schedule for our debt
repayment requirements,  including capitalized leases and related maturities, at
December 31, 2004:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
                                     Long-Term             Capital
 (In Thousands of Dollars)               Debt               Leases            Total
--------------------------------------------------------------------------------------
<S>                                  <C>                   <C>             <C>
 Repayments:
     2005                           $    15,000           $ 1,103         $    16,103
     2006                               512,000             1,006             513,006
     2007                                     -             1,063               1,063
     2008                               605,000             1,129             606,129
     2009                               412,250             1,197             413,447
     Thereafter                       2,898,200             6,335           2,904,535
--------------------------------------------------------------------------------------
                                    $ 4,442,450          $ 11,833         $ 4,454,283
--------------------------------------------------------------------------------------
</TABLE>



                                       135
<PAGE>


Note 7. Contractual Obligations, Financial Guarantees and Contingencies

Lease Obligations:  Lease costs included in operation expense were $67.7 million
in 2004 reflecting,  primarily,  the lease of KeySpan's Brooklyn headquarters of
$14.4  million.  Further,  in May 2004 KeySpan  entered  into a leveraged  lease
financing  arrangement  associated  with the  Ravenswood  Expansion.  The yearly
operating  lease expense is expected to be  approximately  $17 million per year.
For the period May 2004 through December 31, 2004 lease expense  associated with
this  lease  was  $10.5   million.   (See  the  caption  below   "Sale/Leaseback
Transaction" for further details of this lease.) Lease costs also include leases
for other buildings,  office equipment,  vehicles and power operated  equipment.
Lease costs for the year ended December 31, 2003 and 2002 were $82.1 million and
$71.1 million,  respectively. As previously mentioned, the Master Lease has been
consolidated  and, as a result,  lease  payments in 2004 have been  reflected as
interest  expense on the  Consolidated  Statement of Income.  The future minimum
cash lease  payments  under  various  leases,  excluding  the  Master  Lease but
including the Ravenswood Expansion lease, all of which are operating leases, are
$91.5  million  per year over the next five  years and  $552.7  million,  in the
aggregate,  for  all  years  thereafter.   (See  discussion  below  for  further
information   regarding   the  Master   Lease  and  the   Ravenswood   Expansion
sale/leasback transaction.)

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.
Interest expense for the year ended December 31, 2004 was $29.9 million.

The initial term of the Master  Lease  expired on June 20, 2004 and was extended
until June 20,  2009  pursuant to the terms of the Master  Lease.  On all future
semi-annual  payment  dates,  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; or (ii)  terminate  the Master Lease and dispose of the facility.  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.


                                       136
<PAGE>


We have  classified  the Master Lease as $412.3 million of long-term debt on the
Consolidated  Balance Sheet based on our current status as primary  beneficiary.
Further,  we have 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
$339.6 million.

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.

Sale/leaseback  Transaction:  KeySpan  also  has  a  leveraged  lease  financing
arrangement associated with the Ravenswood Expansion.  In May 2004, the unit was
acquired  by  a  lessor  from  our  subsidiary,  KeySpan  Ravenswood,  LLC,  and
simultaneously  leased back to that  subsidiary.  All the obligations of KeySpan
Ravenswood,  LLC have been  unconditionally  guaranteed  by KeySpan.  This lease
transaction  generated cash proceeds of $385 million,  before transaction costs,
which  approximates  the fair market value of the  facility,  as determined by a
third-party  appraiser.  This lease transaction  qualifies 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 has an initial term of 36 years and the yearly  operating
lease  expense is  approximately  $17  million  per year.  Lease  payments  will
fluctuate from year to year, but are substantially paid over the first 16 years.
The future minimum cash lease payments  under this lease is  approximately  $142
million over the next five years and $457  million,  in the  aggregate,  for all
years thereafter.  The sale/leaseback  transaction resulted in a pre-tax gain of
approximately $6 million which has been deferred and is being amortized over the
life of the lease.

Asset Retirement Obligations: In 2003, KeySpan adopted SFAS 143, "Accounting for
Asset  Retirement  Obligations."  SFAS 143 required us to record a liability and
corresponding   asset  representing  the  present  value  of  legal  obligations
associated  with the retirement of tangible,  long-lived  assets that existed at
the inception of the obligation. At the time of implementation, KeySpan recorded
an asset  retirement  obligation  ("ARO")  related to its  investment in Houston
Exploration  and its other  gas  exploration  and  production  subsidiaries.  At
January  1,  2003 the ARO was  $57.2  million.  As a result  of  additions  from
purchases  and  drilling  during  2003 the ARO  increased  to $92.4  million  at
December  31,  2003.   Since   Houston   Exploration's   operations   have  been
deconsolidated,  Houston  Exploration's  liability  is no  longer  reflected  on
KeySpan's  Consolidated  Balance Sheet at December 31, 2004.  The remaining ARO,
therefore,   is  related  to  our  continuing  gas  exploration  and  production
activities and was approximately $1.9 million at December 31, 2004.


                                       137
<PAGE>


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 has been 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 such obligation.

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, 2004, 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      Expiration
   (In Thousands of Dollars)                                           Exposure         Dates
-----------------------------------------------------------------------------------------------------
<S>                                                   <C>             <C>           <C>
Guarantees for Subsidiaries
   Medium-Term Notes - KEDLI                           (i)           $   525,000     2008 - 2010
   Industrial Development Revenue Bonds                (ii)              128,000         2027
   Ravenswood - Master Lease                           (iii)             425,000         2009
   Ravenswood - Sale/leaseback                         (iv)              385,000         2040
   Surety Bonds                                        (v)               258,000     2005 - 2008
   Commodity Guarantees and Other                      (vi)               74,000         2005
   Letters of Credit                                   (vii)              74,000         2005
-------------------------------------------------------------------------------------------------------
                                                                     $ 1,869,000
-------------------------------------------------------------------------------------------------------
</TABLE>


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

(i)  KeySpan has fully and unconditionally guaranteed $525 million to holders of
     Medium-Term  Notes  issued  by KEDLI.  These  notes are due to be repaid on
     January  15, 2008 and  February  1, 2010.  KEDLI is required to comply with
     certain financial  covenants under the debt agreements.  The face values 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  two
     electric-generation peaking plants on long Island. The face values 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 Master Lease. The initial term of the
     lease  expired on June 20, 2004 and was extended  until June 20, 2009.  The
     Master  Lease  is  classified  as  $412.3  million  long-term  debt  on the
     Consolidated Balance Sheet.


                                       138
<PAGE>


(iv) KeySpan has guaranteed all payment and  performance  obligations of KeySpan
     Ravenswood, LLC, the lessee under the sale/leaseback transaction associated
     with the 250 MW Ravenswood Expansion.  The initial term of the lease is for
     36 years. As noted  previously,  this lease qualifies as an operating lease
     and is not reflected on the Consolidated Balance Sheet.

(v)  KeySpan  has  agreed  to  indemnify  the  issuers  of  various  surety  and
     performance bonds associated with certain  construction  projects currently
     being  performed  by certain  current  and former  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. KeySpan will continue to
     provide this guarantee for the mechanical  contracting companies throughout
     the  construction  period  of the  currently  outstanding  projects.  It is
     contemplated  that the majority of the current  contracts will be completed
     by the  end  of  2005.  In  addition,  as  discussed  in  Note  11  "Energy
     Services-Discontinued  Operations",  a performance  and payment bond issued
     for the benefit of a former  subsidiary with respect to a pending  project,
     which  bond had  been  supported  by a $150  million  indemnity  obligation
     included in the table above,  has been replaced.  KeySpan has also received
     from a  former  subsidiary  an  indemnity  bond  issued  by a  third  party
     insurance  company,  the  purpose  of which is to  reimburse  KeySpan in an
     amount up to $80 million in the event it is  required to perform  under all
     other indemnity obligations  previously incurred by KeySpan to support such
     company's bonded projects existing prior to divestiture.

(vi) 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, 2004.

(vii)KeySpan has arranged  for stand-by  letters of credit to be issued to third
     parties that have extended credit to certain subsidiaries.  Certain vendors
     require us to post  letters of credit to guarantee  subsidiary  performance
     under our contracts and to ensure payment 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.


                                       139
<PAGE>


     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  or  former   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.

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 $485 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  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 June 2004,
the parties reached an agreement in principle to settle the  consolidated  class
action lawsuit for $13.8 million.  The proposed  settlement provides for KeySpan
to make  certain  payments  to  plaintiffs,  all of which is to be funded by the
insurance  carrier  providing  liability  coverage for  KeySpan's  directors and
officers.  While  KeySpan  continues  to deny any  wrongdoing,  we  believe  the
proposed settlement is in the best interest of KeySpan and its shareholders. The
settlement  is  subject  to  court  approval,  the  timing  of which  cannot  be
determined.

On February 9, 2005,  KeySpan was served with a  shareholder  derivative  action
asserting  claims on behalf of KeySpan based upon breach of fiduciary  duty. The
complaint, which was filed in the New York State Supreme Court for the County of
Kings,  relates to the 2001 Roy Kay related  losses and alleges  that  KeySpan's
directors and certain senior officers  breached their fiduciary duties when they
placed  their own  personal  interests  above the  interests of KeySpan by using
material  non-public  information  (the fraud at Roy Kay) to sell  securities at
artificially inflated prices.

This new complaint asserts  essentially the same allegations as contained in two
prior federal  shareholder  derivative  actions which were  commenced in October
2001 and June 2002.  On March 15, 2004,  KeySpan and the  individual  defendants
filed a motion to dismiss those earlier federal  complaints.  On April 14, 2004,
the plaintiffs filed a notice of voluntary withdrawal of their actions. On April


                                       140
<PAGE>


23, 2004, the federal court  dismissed both actions without  prejudice.  KeySpan
intends to file a motion to dismiss this new complaint. While KeySpan denies any
wrongdoing, the outcome of this proceeding cannot be determined as yet.

In late  2001,  KeySpan  received  inquires  from  the U.S.  Attorney's  Office,
Southern  District  of New  York  and  the  SEC  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.

In March 2002, the SEC issued a formal order of investigation  pursuant to which
it  indicated  that it would  review the  trading  activity  of certain  company
insiders as well as KeySpan's  compliance with reporting rules and  regulations,
generally  during the period  following the acquisition of the Roy Kay companies
through the July 17, 2001 announcement. Since mid 2002, KeySpan has not received
any further notifications or inquires concerning any of these matters.

KeySpan  subsidiaries,  along with  several  other  parties,  have been named as
defendants in numerous  proceedings filed by plaintiffs claiming various degrees
of injury from asbestos exposure at generating facilities formerly owned by Long
Island Lighting  Company  ("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
("PSA") between LIPA and KeySpan.

KeySpan  is  unable  to  determine  the  outcome  of  the  outstanding  asbestos
proceedings,  but does not believe that such  outcome,  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  PSA,  its
indemnification  rights against third parties and its insurance  coverage (above
applicable  deductible  limits)  cover its  exposure  for  asbestos  liabilities
generally.

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 29, 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,
results of operations or cash flows.

In addition,  LIPA is in the process of performing a long-term  strategic review
initiative regarding its future direction. It has engaged a team of advisors and
consultants and is conducting public hearings to develop  recommendations  to be
submitted  to the LIPA  Trustees.  Some of the  strategic  options  that LIPA is
considering  include  whether  LIPA  should  continue  its  operations  as  they


                                       141
<PAGE>


presently  exist,  fully  municipalize  or privatize,  sell some, but not all of
their  assets and become a regulator  of rates and  services.  In the near term,
LIPA must make a determination  by May 2005 as to whether they will exercise its
option to purchase our Long Island  generating  plants  pursuant to the terms of
the Generation  Purchase Rights  Agreement.  Until LIPA makes a determination on
its  future  direction,  we are  unable to  determine  what the  outcome of this
strategic review will have on our financial condition,  results of operations or
cash flows.  Any action  that may be taken will have to take into  consideration
the long-term nature of our existing contracts.

Environmental Matters

Air: With respect to NOx emissions reduction requirements for our existing power
plants,  our investments in low NOx 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  by May 1, 2003 under
Phase  I,  II  and  III  of  the  Ozone  Transport  Commission  memorandum  in a
cost-effective  manner.  We have achieved and expect to continue to achieve such
emission  reductions through the use of low NOx combustion control systems,  the
use of natural  gas fuel  and/or  the  purchases  of  emission  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 to enhance compliance options.

Water:  Additional  capital  expenditures  associated  with the  renewal  of the
surface water discharge  permits for our power plants will likely be required by
the  Department  of  Environmental   Conservation   ("DEC").  We  are  currently
conducting  studies  as  directed  by the DEC to  determine  the  impacts of our
discharges on aquatic resources.  It is not possible at this time to predict the
extent of such  capital  investments  since they will depend upon the outcome of
the ongoing  studies and the  subsequent  determination  by the DEC to apply the
standards set forth in recently  promulgated  federal  regulations under Section
316 of the Clean Water Act designed to mitigate such impacts.

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.  KeySpan  submitted  applications to the DEC for
each of the remaining  sites in August 2004 under the DEC's  Brownfield  Cleanup
Program  ("BCP").  As a result of a recent United States Supreme Court decision,
KeySpan is currently  reevaluating its continued  participation in the DEC's BCP


                                       142
<PAGE>


and VCA  programs.  Under the Supreme  Court's  ruling in Cooper  Industries  v.
Aviall,  KeySpan would be prohibited from bringing a contribution action against
other  responsible  parties  under  the  Comprehensive  Environmental  Response,
Compensation  and  Liability  Act  unless  KeySpan  had been sued by the DEC and
received a verdict  against it or reached a  settlement  of the action  with the
DEC.

We have  identified 28 of these sites as being  associated  with the  historical
operations of KEDNY. One site has been fully  remediated.  Subject to the issues
described  in  the  preceding   paragraph,   the  remaining  27  sites  will  be
investigated  and, if necessary,  remediated  under the terms and  conditions of
ACOs, VCAs or Brownfield Cleanup Agreements  ("BCA").  Expenditures  incurred to
date by us with respect to KEDNY MGP-related activities total $47.8 million.

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 $42.7 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, VCAs or
BCAs.

We presently  estimate  the  remaining  cost of our KEDNY and KEDLI  MGP-related
environmental  remediation  activities will be $206.6 million,  which amount has
been  accrued by us as a  reasonable  estimate of probable  cost for known sites
however,  remediation  costs for each site may be materially  higher than noted,
depending upon changing technologies and regulatory standards,  selected end use
for each site, and actual environmental  conditions encountered and as a result,
it is  possible  that  remediation  costs  could be up to $258  million  higher.
Expenditures incurred to date by us with respect to these MGP-related activities
total $90.5 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,  2004,  we have  reflected a regulatory  asset of $228.7
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,  2004,  these  previously
deferred regulatory  liabilities totaled $37 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. That petition
is still pending.

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 $3.1  million,  which amount has been
accrued by us. Expenditures incurred to date total $1.9 million.


                                       143
<PAGE>


New England Sites: Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 77 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 67 of
these sites. A subsidiary of National Grid USA ("National  Grid"),  formerly New
England Electric System, has assumed  responsibility for remediating 11 of these
sites,  subject  to a limited  contribution  from  Boston Gas  Company,  and has
provided full  indemnification to Boston Gas Company with respect to eight other
sites.  In  addition,  Boston Gas Company,  Colonial Gas Company,  and Essex Gas
Company have assumed  responsibility  for remediating  three sites each. 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.

We  presently  estimate  the  remaining  cost  of  these   Massachusetts   KEDNE
MGP-related environmental cleanup activities will be $14.9 million, which amount
has been  accrued by us as a  reasonable  estimate  of  probable  cost for known
sites,  however  remediation  costs for each site may be materially  higher than
noted,  depending upon changing technologies and regulatory standards,  selected
end use for each site, and actual environmental  conditions encountered and as a
result, it is possible that remediation costs could be up to $73 million higher.
Expenditures  incurred since November 8, 2000, the date KeySpan acquired Eastern
Enterprises, with respect to these MGP-related activities total $22.5 million.

Boston Gas Company  reached  settlements  with  certain  insurance  carriers for
recovery of a portion of previously incurred environmental expenditures. Under a
previously issued MADTE rate order, insurance and third-party recoveries,  after
deducting  legal fees, are shared between Boston Gas and its firm gas customers.
As a result of these  settlements,  in 2004  Boston  Gas  Company  recorded a $5
million benefit to operations and maintenance expense.

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.

We  presently   estimate  the   remaining   cost  of   EnergyNorth   MGP-related
environmental  cleanup  activities will be $12.5 million,  which amount has been
accrued by us as a reasonable estimate of probable cost for known sites however,
remediation costs for each site may be materially  higher than noted,  depending


                                       144
<PAGE>


upon changing technologies and regulatory  standards,  selected end use for each
site, and actual  environmental  conditions  encountered and as a result,  it is
possible that remediation costs could be up to $13 million higher.  Expenditures
incurred since November 8, 2000,  with respect to these  MGP-related  activities
total $10.3 million.

By rate  orders,  the MADTE  and the  NHPUC  provide  for the  recovery  of site
investigation and remediation costs and,  accordingly,  at December 31, 2004, we
have reflected a regulatory  asset of $43.8 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 orders 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.

In 2004,  KeySpan  reached a settlement with insurance  carriers  regarding cost
recovery  for  expenses at one of the above  noted  sites and  recorded an $11.6
million  reduction to operating  expenses.  We presently  estimate the remaining
cost of our  environmental  cleanup  activities for the three  non-utility sites
will be  approximately  $19.7 million,  which amount has been accrued by us as a
reasonable estimate of probable costs for known sites however, remediation costs
for each site may be  materially  higher than  noted,  depending  upon  changing
technologies  and  regulatory  standards,  selected  end use for each site,  and
actual environmental conditions encountered and as a result, it is possible that
remediation costs could be up to $57 million higher. Expenditures incurred since
November 8, 2000, with respect to these sites total $13.1 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 may be  required  to


                                       145
<PAGE>


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.

Insurance  Reimbursement  of MGP Response Costs: We have instituted  lawsuits in
New York,  Massachusetts and New Hampshire against numerous  insurance  carriers
for  reimbursement  of costs incurred for the  investigation  and remediation of
these MGP sites.

In January 1998 and July 2001, KEDLI and KEDNY,  respectively,  filed complaints
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 and KEDNY. The outcome of these proceedings  cannot
yet be determined.

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.  And 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 yet be determined.

EnergyNorth  has filed a number of lawsuits 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. The outcome of these proceedings cannot yet
be determined.

In 1993 KeySpan New England LLC filed a declaratory  judgment action against the
Hanover and Travelers  insurance  companies in the Superior  Court for Middlesex
County for the Everett Facility ("the Eastern  Action").  Eastern sought to have
the  court  compel  the  Insurers  to  defend  Eastern  in  connection  with the
Massachusetts DEP's Notice of Responsibility ("NOR"). In 2004, the Court granted
KeySpan's  unopposed motion for leave to file a Second Amended  Complaint in the
Eastern  Action to seek a  declaratory  ruling that the insurers  have a duty to
indemnify  KeySpan  for the costs  associated  with the  Everett NOR and certain
other related private  actions.  The Second Amended  Complaint also adds certain
excess  insurance  carriers as defendants in the Eastern Action.  The outcome of
this proceeding cannot yet be determined.

Settlement  negotiations  have been ongoing while the  litigation of these cases
have been proceeding.  Over the past four years KeySpan has achieved settlements
with various  insurance  carriers in excess of $50 million for  reimbursement of
MGP response costs incurred in New York, Massachusetts and New Hampshire.


                                       146
<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  distribution
operations,   gas  exploration  and  production   activities  and  its  electric
generating facilities at the Ravenswood site.

Derivative financial instruments are employed by our gas distribution operations
to reduce the cash flow  variability  associated  with the purchase  price for a
portion  of  future  natural  gas  purchases  for our  regulated  firm gas sales
customers.  The accounting for these  derivative  instruments is subject to SFAS
71. See the caption  below "Firm Gas Sales  Derivative  Instruments  - Regulated
Utilities" for a further  discussion of these  derivatives.  Certain  derivative
instruments employed by our gas distribution  operations are not subject to SFAS
71. Utility tariffs applicable to certain  large-volume  customers permit gas to
be sold at prices  established  monthly relative to a prevailing  alternate fuel
price  but  limited  to the cost of gas plus the tail  block  rate.  KEDNY  uses
over-the-counter  ("OTC") natural gas swaps,  with  offsetting  positions in OTC
fuel oil swaps of equivalent energy value, to hedge the cash-flow variability of
specified  portions of gas purchases and sales  associated with these customers.
The  maximum  length of time over  which we have  hedged  cash flow  variability
associated with forecasted purchases and sales of natural gas is through October
2005. We use standard New York Mercantile  Exchange  ("NYMEX") futures prices to
value the gas and heating oil positions. At December 31, 2004, the fair value of
gas swap  contracts was a liability of $6.2  million;  the fair value of the oil
swap  contracts was an asset of $7.5  million.  These  derivative  positions are
expected to be reclassified from other  comprehensive  income into earnings over
the next twelve months.

Seneca-Upshur  utilizes OTC natural gas swaps to hedge the cash flow variability
associated with forecasted sales of a portion of its natural gas production.  At
December 31, 2004,  Seneca-Upshur has hedge positions in place for approximately
85% of its estimated 2005 through 2007 gas production,  net of gathering  costs.
We use market quoted forward prices to value these swap  positions.  The maximum
length of time over which Seneca-Upshur has hedged such cash flow variability is
through  December  2007.  The  fair  value of these  derivative  instruments  at
December 31, 2004 was a liability of $0.7 million. The estimated amount of gains
associated  with  such  derivative   instruments  that  are  reported  in  other
comprehensive income and that are expected to be reclassified into earnings over
the next twelve months is $0.2 million, or approximately $0.1 million after-tax.

The Ravenswood Projects use 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  Projects also
hedge the cash flow  variability  associated  with a portion of electric  energy
sales.


                                       147
<PAGE>


With respect to price exposure associated with fuel purchases for the Ravenswood
Projects,  KeySpan employs natural gas futures  contracts 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 by the  Ravenswood  Projects.  We use standard  NYMEX futures prices to
value the gas futures  contracts and market quoted  forward  prices to value oil
swap  contracts.  The maximum length of time over which we have hedged cash flow
variability  associated  with  forecasted  purchases  of natural  gas is through
September 2005. The fair value of these  derivative  instruments at December 31,
2004 was  negligible.  The maximum length of time over which we have hedged cash
flow  variability  associated with  forecasted  purchases of fuel oil is through
April 2006. The fair value of these derivative  instruments at December 31, 2004
was $0.3 million. A substantial portion of these derivative  instruments,  which
are reported in other comprehensive income, 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  electric energy
sales from the Ravenswood  Projects.  Our hedging  strategy is to hedge at least
50% of forecasted  on-peak summer season  electric energy sales and a portion of
forecasted  electric  energy sales for the  remainder  of the year.  The maximum
length of time  over  which we have  hedged  cash flow  variability  is  through
December 2005. We use market quoted  forward  prices to value these  outstanding
derivatives.  The fair market value of these derivative  instruments at December
31,  2004 was $0.4  million all of which is  expected  to be  reclassified  into
earnings over the next twelve months. The after-tax benefit is anticipated to be
$0.2 million.

The above  noted  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 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  affects
earnings.  Gains and losses are  reflected as a component  of either  revenue or
fuel  and  purchased   power   depending  on  the  hedged   transaction.   Hedge
ineffectiveness,  which was negligible in 2004,  results from changes during the
period in the price  differentials  between  the index  price of the  derivative
contract  and the price of the  purchase or sale for the cash flow that is being
hedged, and is recorded directly to earnings.

The table below  summarizes  the fair value of  outstanding  financially-settled
commodity  derivative  instruments that qualify for hedge accounting at December
31, 2004 and the 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. It
should be noted that in the table  below,  December  31, 2003  balances  include
outstanding  derivatives of Houston Exploration;  no such derivative instruments
are included in the December 2004 balances  since Houston  Exploration  was sold
during the year.


                                       148
<PAGE>


<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
(In Thousands of Dollars)                                  December 31, 2004      December 31, 2003
----------------------------------------------------------------------------------------------------
<S>                                                                  <C>                  <C>
Gas Contracts:
  Other current assets                                               $   215              $   3,458
  Accounts payable and other liabilities                              (6,149)               (35,592)
  Other deferred liabilities                                            (879)                (4,734)

Oil Contracts:
  Other current assets                                                 7,719                      -
  Other deferred charges                                                   -                    385

Electric Contracts:
  Other current assets                                                   353                      -
  Other deferred charges                                                   -                    259
----------------------------------------------------------------------------------------------------
                                                                     $ 1,259              $ (36,224)
----------------------------------------------------------------------------------------------------
</TABLE>


Financially-Settled  Commodity  Derivative  Instruments  that Do Not Qualify for
Hedge  Accounting:  KeySpan  subsidiaries also have employed a limited number of
financial  derivatives that do not qualify for hedge accounting  treatment under
SFAS 133. In 2004,  we purchased a series of call options on the spread  between
the price of heating oil and the price of natural  gas.  The  options  cover the
period  February 2005 through  October 2005 and further  complement  our hedging
strategy  noted above  regarding  sales to certain  large-volume  customers.  As
stated,  we sell gas to certain  large-volume  customers  at prices  established
monthly relative to a prevailing alternate fuel price but limited to the cost of
gas plus the tail block rate. Utility tariffs, however, establish an upper limit
on the price KeySpan can charge for the sale of natural gas to these  customers.
These  options  are  intended to limit  KeySpan's  exposure to heating oil price
spikes.  These options do not qualify for hedge accounting  treatment under SFAS
133. We recorded a $2.5  million  charge in other income and  deductions  on the
Consolidated  Statement  of Income to reflect  the  change in the  market  value
associated with this derivative instrument.

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. 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, 2004, these
derivatives  had a negative  fair value of $10.4  million and are reflected as a
regulatory asset on the Consolidated Balance Sheet.

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,  2004,  these  derivatives  had a
negative  fair market value of $16.5  million and are  reflected as a regulatory
liability of $7.4 million and a  regulatory  asset of $23.9 on the  Consolidated
Balance Sheet.


                                       149
<PAGE>


Interest  Rate  Derivative  Instruments:  In 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 received the fixed
coupon  rate  associated  with these  bonds and paid our swap  counterparties  a
variable  interest rate based on LIBOR,  that was reset on a semi-annual  basis.
These swaps were  designated as fair-value  hedges and qualified for "short-cut"
hedge accounting treatment under SFAS 133. In the first quarter of 2004, we paid
our counterparty an average interest rate of 6.44%, and as a result, we realized
interest savings of $0.5 million.

On April 7, 2004 we terminated  these swap  agreements and received $1.2 million
from our swap  counterparties,  of which $0.7 million  represented  accrued swap
interest.  The  difference  between the  termination  settlement  amount and the
amount of accrued interest,  $0.5 million,  was being recorded as a reduction to
interest  expense  over the  remaining  life of the bonds.  In August  2004,  we
redeemed these bonds and recorded the remaining benefit.

KeySpan  has  a  leveraged  lease  financing  arrangement  associated  with  the
Ravenswood  Expansion.  In May 2004,  the facility was acquired by a lessor from
our subsidiary,  KeySpan Ravenswood, LLC, and simultaneously leased back to that
subsidiary. In connection with this sale/leaseback transaction, KeySpan utilized
a $275  million  treasury  lock (at  4.2%)  to hedge  the  10-year  US  Treasury
component of the underlying notes issued by the lessor to purchase the facility.
The  treasury  lock was in effect for a five-week  period  during which time the
10-year US Treasury  increased 70 basis points.  KeySpan did not designate  this
derivative  instrument  as a hedge for  accounting  purposes.  The treasury lock
settled in May 2004 and KeySpan  received  cash  proceeds of $12.6 million which
was recorded in other income and (deductions) in the  Consolidated  Statement of
Income.  (See  Note  7.  "Contractual  Obligations,   Financial  Guarantees  and
Contingencies"   for  additional   information   regarding  the   sale/leaseback
transaction.)

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.


                                       150
<PAGE>


In 2003,  KEDNE  entered  into  heating-degree  day call and put options for the
2003/2004 winter heating season - November 2003 through March 2004. With respect
to sold call  options,  KeySpan  was  required  to make a payment of $27,500 per
heating degree day to its counterparties  when actual weather experienced during
this  time  frame  was  above  4,440  heating  degree  days,  which  equates  to
approximately  2% colder  than  normal  weather,  based on the then most  recent
20-year average for normal  weather.  The maximum amount KeySpan was required to
pay on its sold call options was $5.5  million.  With  respect to purchased  put
options,  KeySpan would have  received a $27,500 per heating  degree day payment
from its counterparties when actual weather was below 4,266 heating degree days,
or  approximately  2% warmer than normal.  The maximum amount KeySpan would have
received on its purchased put options was $11 million.  The net premium cost for
these options was $0.4 million.  During the first quarter of 2004,  weather,  as
measured  in heating  degree-days,  was 9.4% colder than normal and, as a result
$4.1 million was recorded as a reduction to revenues.

In 2004, we entered into  heating-degree  day put options to mitigate the effect
of fluctuations from normal weather on KEDNE's financial position and cash flows
for the  2004/2005  winter  heating  season - November  2004 through March 2005.
These put options will pay KeySpan up to $40,000 per heating degree day when the
actual  temperature  is below 4,130  heating  degree days, or  approximately  5%
warmer than normal, based on the most recent 20-year average for normal weather.
The maximum  amount  KeySpan may receive on these  purchased  put options is $16
million.  The net premium  cost for these  options was $1.6 million and is being
amortized over the heating  season.  Unlike  previous years if weather is colder
than normal KeySpan will have no financial obligation.  Since weather was colder
than normal during the fourth quarter,  there was no earnings impact  associated
with these derivative instruments.  We account for these derivatives pursuant to
the  requirements of EITF 99-2,  "Accounting for Weather  Derivatives."  In this
regard, such instruments are accounted for using the "intrinsic value method" as
set forth in such guidance.

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.


                                       151
<PAGE>


Long-term Debt: The following  tables depict the fair values and carrying values
of KeySpan's long-term debt at December 31, 2004 and 2003.

Fair Values of Long-Term Debt
------------------------------------------------------------------------------
                                                        December 31,
(In Thousands of Dollars)                         2004                 2003
------------------------------------------------------------------------------
First Mortgage Bonds                        $   115,820           $   178,438
Notes                                         2,571,847             3,893,158
Gas Facilities Revenue Bonds                    666,941               683,354
Authority Financing Notes                        66,005                66,005
Promissory Notes                                159,791               158,837
MEDS Equity Units                               479,964               495,880
Master Lease                                    460,896               474,912
Tax Exempt Bonds                                134,949               129,558
------------------------------------------------------------------------------
                                            $ 4,656,213           $ 6,080,142
------------------------------------------------------------------------------


Carrying Values of Long-Term Debt
-----------------------------------------------------------------------------
                                                        December 31,
(In Thousands of Dollars)                        2004                 2003
-----------------------------------------------------------------------------
First Mortgage Bonds                       $    95,000           $   153,186
Notes                                        2,485,000             3,456,425
Gas Facilities Revenue Bonds                   640,500               648,500
Authority Financing Notes                       66,005                66,005
Promissory Notes                               155,420               155,422
MEDS Equity Units                              460,000               460,000
Master Lease                                   412,250               412,250
Tax Exempt Bonds                               128,275               128,275
-----------------------------------------------------------------------------
                                           $ 4,442,450           $ 5,480,063
-----------------------------------------------------------------------------

Our subsidiary  debt was 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 Midland 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.

In 2001 we recorded a discontinued operations loss on disposal. 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 2001 loss  provision.
These  changes  resulted  in an  additional  after tax loss on disposal of $19.7
million.


                                       152
<PAGE>


The  following  is  selected  financial  information  for Midland for the period
January 1, 2002 through July 2, 2002:


---------------------------------------------------------------------------
(In Thousands of Dollars)                                           2002
---------------------------------------------------------------------------
Revenues                                                         $ 116,149
Pre-tax income (loss)                                               (4,624)
Income tax (expense) benefit                                         1,268
---------------------------------------------------------------------------
Income (loss) from discontinued operations                          (3,356)
---------------------------------------------------------------------------
Estimated book gain on disposal                                      5,980
Tax expense associated with disposal                               (22,286)
---------------------------------------------------------------------------
Estimated loss on disposal                                         (16,306)
---------------------------------------------------------------------------
Loss from discontinued operations                                $ (19,662)
---------------------------------------------------------------------------


10. Gas Exploration and Production Property - Depletion

As  described  in Note 2  "Business  Segments,"  during  much of 2004  KeySpan's
investments  in gas  exploration  and  production  activities  consisted  of its
ownership  interest in Houston  Exploration,  as well as KeySpan's  wholly-owned
subsidiary KeySpan Exploration and Production, which is still engaged in a joint
drilling program with Houston  Exploration.  Further,  KeySpan's  investments in
these activities also includes its wholly-owned subsidiary Seneca-Upshur.  These
assets were  accounted for under the full cost method of  accounting.  After the
sale of Houston Exploration, Seneca-Upshur and KeySpan Exploration have remained
on full  cost  accounting.  Under the full cost  method,  costs of  acquisition,
exploration  and  development  of  natural  gas  and  oil  reserves  plus  asset
retirement  obligations  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.

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 prices  increase.  The ceiling test is calculated using natural gas
and oil prices in effect as of the balance sheet date,  adjusted for outstanding
derivative instruments, held flat over the life of the reserves.

As a result of the June 2004 stock  transaction  discussed  in Note 2  "Business
Segments",  KeySpan  accounted for its investment in Houston  Exploration on the
equity  method  from  June  2004  through   November  19,  2004,  i.e.   Houston
Exploration's   operations   were  not   consolidated   with   KeySpan's   other
subsidiaries. Therefore, we were required to calculate a ceiling test on KeySpan
Exploration and Production's and Seneca-Uphsur's assets independently of Houston
Exploration's  assets in the second quarter of 2004. Based on a report furnished
by an independent  reservoir  engineer at that time, it was determined  that the


                                       153
<PAGE>


remaining  proved  undeveloped oil reserves held in the joint venture required a
substantial  investment  in order to  develop.  Therefore,  KeySpan  and Houston
Exploration  elected  not to develop  these oil  reserves.  As a result,  in the
second quarter of 2004,  KeySpan  recorded a $48.2 million  non-cash  impairment
charge  to  write  down  its   wholly-owned   gas   exploration  and  production
subsidiaries'  assets.  This charge was recorded in depreciation,  depletion and
amortization on the Consolidated Statement of Income.

11.   Energy Services - Discontinued Operations

The Energy  Services  segment  has  experienced  significantly  lower  operating
profits  and cash flows  than  originally  projected.  As  previously  reported,
management has reviewed the operating  performance of this segment. At a meeting
held on November 2, 2004, KeySpan's Board of Directors authorized  management to
begin the  process  of  disposing  of a  significant  portion  of its  ownership
interests in certain companies within the Energy Services segment - specifically
those companies  engaged in mechanical  contracting  activities.  In January and
February of 2005,  KeySpan  sold its  mechanical  contracting  investments.  The
operating  results  and  financial  position  of  these  companies,  which  were
previously  consolidated within the Energy Services segment, have been reflected
as discontinued operations on the Consolidated Statement of Income, Consolidated
Balance Sheet and Consolidated Statement of Cash Flows.

In regard  to the  January  2005  transactions,  KeySpan  received  proceeds  of
approximately  $16  million,  approximately  $5  million  of which is to be paid
within a three  year  period.  In  addition,  KeySpan  retained  its  previously
incurred indemnity support  obligations  related to certain surety,  performance
and payment bonds issued for the benefit of KeySpan's former  subsidiaries prior
to closing.  The current estimated cost to complete  projects  supported by such
indemnity  obligations is approximately  $25 million.  The buyers have agreed to
cooperate with KeySpan to seek a release of KeySpan's indemnity  obligation with
respect to all or a portion of such outstanding  bonds after closing.  Any costs
incurred to obtain such release will be borne by KeySpan.

In connection  with the February 2005  transaction,  KeySpan paid or contributed
approximately  $26  million to its former  subsidiary  prior to closing the sale
transaction in exchange for, among other things,  the disposition of outstanding
shares in the former subsidiary and the settlement of intercompany  advances and
replacement  of a  performance  and  payment  bond issued for the benefit of its
former  subsidiary  with  respect  to a  pending  project,  which  bond had been
supported  by a $150  million  indemnity  obligation  of KeySpan.  In  addition,
KeySpan received from its former  subsidiary an indemnity bond issued by a third
party  insurance  company,  the purpose of which is to  reimburse  KeySpan in an
amount up to $80 million in the event it is required to perform  under all other
indemnity  obligations  previously  incurred by KeySpan to support the remaining
bonded projects of its former  subsidiary as of the closing.  As of February 11,
2005, the total cost to complete such remaining  bonded projects is estimated to
be approximately  $70 million.  The  aforementioned  guarantees are reflected in
Note 7 "Contractual Obligations, Financial Guarantees and Contingencies".


                                       154
<PAGE>


In  anticipation  of these sales and in connection  with the  preparation of the
third quarter and fourth  quarter  financial  statements,  KeySpan  conducted an
evaluation  of the  carrying  value of  these  investments,  including  recorded
goodwill.  Further,  we evaluated the carrying  value of goodwill for the entire
Energy Services segment. As noted in prior SEC filings, KeySpan records goodwill
on purchased transactions,  representing the excess of acquisition cost over the
fair value of net assets acquired.

As  a  result  of  these  evaluations,  KeySpan  recorded  a  non-cash  goodwill
impairment  charge of $108.3  million  ($80.3  million  after tax,  or $0.50 per
share) in 2004.  This charge was  recorded as follows:  (i) $14.4  million as an
operating  expense  on the  Consolidated  Statement  of  Income  reflecting  the
write-down of goodwill on Energy Services segment's continuing  operations;  and
(ii)  $93.9  million  ($67.8  million  after-tax)  as  discontinued   operations
reflecting the impairment on the mechanical contracting companies.

In addition,  an impairment charge of $100.3 million ($72.1 million after-tax or
$.45 per share) was also recorded to reduce the carrying  value of the remaining
assets of the  mechanical  contracting  companies.  This charge is  reflected in
discontinued operations on the Consolidated Statement of Income.

KeySpan employed a combination of two methodologies in determining the estimated
fair value for its investment in the Energy Services segment, a market valuation
approach and an income valuation approach.  Under the market valuation approach,
KeySpan  utilized  a range of  near-term  potential  realizable  values  for the
mechanical contracting businesses. Under the income valuation approach, the fair
value was obtained by discounting  the sum of (i) the expected future cash flows
and (ii) the terminal value. KeySpan utilized certain significant assumptions in
this valuation,  specifically the  weighted-average  cost of capital,  short and
long-term growth rates and expected future cash flows. Approximately $65 million
of goodwill remains in this segment.

The information  below highlights the major classes of assets and liabilities of
the discontinued  mechanical contracting companies,  as well as major income and
expense captions.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------
                                                    December 31,              December 31,
(In Thousands of Dollars)                               2004                      2003
                                             -----------------------------------------------------
<S>                                                   <C>                      <C>
Property                                          $     8,743                $    8,588
Current assets                                    $    42,923                $  181,823
Goodwill                                          $         -                $   92,702

Current liabilities                               $    64,245                $   81,956
--------------------------------------------------------------------------------------------------
</TABLE>



                                       155
<PAGE>


<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                                                                        For the Year Ended December 31,
(In Thousands of Dollars)                                       2004                 2003                     2002
---------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>                  <C>                      <C>
Revenues                                                       338,666              379,637                  505,492
Less:
    Operating expenses                                         364,879              385,496                  472,629
    Goodwill impairment                                        108,289                    -                        -
---------------------------------------------------------------------------------------------------------------------
                                                              (134,502)              (5,859)                  32,863
Income taxes (benefit)                                         (55,542)              (3,971)                  13,815
---------------------------------------------------------------------------------------------------------------------
Operating loss                                                 (78,960)              (1,888)                  19,048
Loss on disposal, net tax of $28,174                           (72,088)                   -                        -
---------------------------------------------------------------------------------------------------------------------
Net Income                                                    (151,048)              (1,888)                  19,048
---------------------------------------------------------------------------------------------------------------------
</TABLE>



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.



                                       156
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                  Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                           Year Ended December 31, 2004
(In Thousands of Dollars)                      Guarantor          KEDLI          Other Subsidiaries     Eliminations    Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                             <C>            <C>                    <C>               <C>              <C>
Revenues                                     $     619        $ 1,124,417            $ 5,526,049       $     (619)      $ 6,650,466
                                        --------------------------------------------------------------------------------------------
Operating Expenses
  Purchased gas                                      -            664,857              1,999,635                -         2,664,492
  Fuel and purchased power                           -                  -                540,302                -           540,302
  Operations and maintenance                     5,287            137,847              1,423,888                -         1,567,022
  Intercompany expense                                              5,391                 (5,391)                                 -
  Depreciation and amortization                                    79,856                471,904                -           551,760
  Operating taxes                                    -             65,722                338,490                -           404,212
  Goodwill Impairment                                -                  -                 40,965                -            40,965
                                        --------------------------------------------------------------------------------------------
Total Operating Expenses                         5,287            953,673              4,809,793                -         5,768,753
                                        --------------------------------------------------------------------------------------------

Gain on sale of property                             -                  -                  7,021                -             7,021
Income from equity investments                       -                  -                 46,536                -            46,536
                                        --------------------------------------------------------------------------------------------
Operating Income (Loss)                         (4,668)           170,744                769,813             (619)          935,270
                                        --------------------------------------------------------------------------------------------

Interest charges                              (204,508)           (61,503)              (267,605)         202,365          (331,251)
Other income and (deductions)                  635,450                836                423,895         (723,946)          336,235
                                        --------------------------------------------------------------------------------------------
Total Other Income and (Deductions)            430,942            (60,667)               156,290         (521,581)            4,984
                                        --------------------------------------------------------------------------------------------

Income Taxes (Benefit)                         (45,459)            35,827                335,173                -           325,541
                                        --------------------------------------------------------------------------------------------
Earnings from Continuing Operations            471,733             74,250                590,930         (522,200)          614,713

Discontinued Operations                              -                                  (151,048)                          (151,048)
                                        --------------------------------------------------------------------------------------------
Net Income                                   $ 471,733        $    74,250            $   439,882       $ (522,200)      $   463,665
                                        ============================================================================================
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>






                                       157
<PAGE>
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                    Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                        Year Ended December 31, 2003
(In Thousands of Dollars)                     Guarantor          KEDLI         Other Subsidiaries     Eliminations      Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                            <C>            <C>                    <C>                <C>              <C>
Revenues                                     $     507       $ 1,046,931            $ 5,488,593        $     (507)      $ 6,535,524
                                         -------------------------------------------------------------------------------------------
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              1,474,029                 -         1,622,592
  Intercompany expense                           5,282             3,570                 (3,570)           (5,282)                -
  Depreciation and amortization                    (53)           77,603                494,119                 -           571,669
  Operating taxes                                    -            77,503                340,733                 -           418,236
                                         -------------------------------------------------------------------------------------------
Total Operating Expenses                        16,569           869,908              4,641,037            (5,282)        5,522,232
                                         -------------------------------------------------------------------------------------------

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                867,811             4,775         1,047,629
                                         -------------------------------------------------------------------------------------------

Interest charges                              (209,505)          (62,992)              (299,399)          264,202          (307,694)
Other income and (deductions)                  621,151            (8,636)                54,315          (699,415)          (32,585)
                                         -------------------------------------------------------------------------------------------
Total Other Income and (Deductions)            411,646           (71,628)              (245,084)         (435,213)         (340,279)
                                         -------------------------------------------------------------------------------------------

Income Taxes (Benefit)                         (28,663)           40,796                269,148                 -           281,281
                                         -------------------------------------------------------------------------------------------
Earnings from Continuing Operations          $ 424,355        $   78,573            $   353,579        $ (430,438)      $   426,069

Discontinued Operations                              -                 -                 (1,888)                             (1,888)
Cumulative  Change in Accounting
Principle                                            -                 -                (37,451)                -           (37,451)
                                         -------------------------------------------------------------------------------------------
Net Income                                   $ 424,355        $   78,573            $   314,240        $ (430,438)      $   386,730
                                         ===========================================================================================
</TABLE>
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                  Statement of Income
------------------------------------------------------------------------------------------------------------------------------
                                                                   Year Ended December 31, 2002
(In Thousands of Dollars)                 Guarantor         KEDLI        Other Subsidiaries     Eliminations      Consolidated
------------------------------------------------------------------------------------------------------------------------------
<S>                                        <C>            <C>                  <C>                 <C>             <C>
Revenues                                 $     463       $ 810,601            $ 4,654,573         $    (463)      $ 5,465,174
                                       ---------------------------------------------------------------------------------------
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              1,572,615                 -         1,631,297
  Intercompany expense                       2,772          79,826                (79,826)           (2,772)                -
  Depreciation and amortization                (44)         65,911                447,841                 -           513,708
  Operating taxes                           (2,149)         80,056                302,620                 -           380,527
                                       ---------------------------------------------------------------------------------------
Total Operating Expenses                    13,904         650,892              3,912,641            (2,772)        4,574,665
                                       ---------------------------------------------------------------------------------------

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                760,337             2,309           909,335
                                       ---------------------------------------------------------------------------------------

Interest charges                          (200,920)        (62,520)              (295,209)          257,145          (301,504)
Other income and (deductions)              565,262           7,835                 60,106          (633,068)              135
                                       ---------------------------------------------------------------------------------------
Total Other Income and (Deductions)        364,342         (54,685)              (235,103)         (375,923)         (301,369)
                                       ---------------------------------------------------------------------------------------

Income Taxes (Benefit)                     (26,683)         36,746                219,601                 -           229,664
                                       ---------------------------------------------------------------------------------------
Earnings from Continuing Operations      $ 377,688       $  68,595            $   305,633         $(373,614)      $   378,302

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

                                       158
<PAGE>


<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                December 31, 2004
(In Thousands of Dollars)                          Guarantor       KEDLI       Other Subsidiaries    Eliminations      Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                               <C>           <C>               <C>                <C>               <C>
ASSETS
Current Assets
   Cash and temporary cash investments           $   580,712   $      (894)     $    342,155        $          -      $    921,973
   Accounts receivable, net                              757       223,616         1,087,679                   -         1,312,052
   Other current assets                                4,496       146,453           650,725                   -           801,674
   Assets of discontinued operations                       -             -            42,923                                42,923
                                          -----------------------------------------------------------------------------------------
                                                     585,965       369,175         2,123,482                   -         3,078,622
                                          -----------------------------------------------------------------------------------------

Investments and others                             4,567,314         2,039           169,063          (4,465,523)          272,893
                                          -----------------------------------------------------------------------------------------
Property
   Gas                                                     -     1,998,525         4,872,696                   -         6,871,221
   Other                                                  13             -         2,987,720                   -         2,987,733
   Accumulated depreciation and depletion                  -      (334,468)       (2,465,305)                  -        (2,799,773)
   Property of discontinued operations                     -             -             8,743                                 8,743
                                          -----------------------------------------------------------------------------------------
                                                          13     1,664,057         5,403,854                   -         7,067,924
                                          -----------------------------------------------------------------------------------------

Intercompany Accounts Receivable                   2,485,740             -         1,292,198          (3,777,938)                -

Deferred Charges                                     381,300       221,393         2,341,998                   -         2,944,691

                                          -----------------------------------------------------------------------------------------
Total Assets                                     $ 8,020,332   $ 2,256,664      $ 11,330,595        $ (8,243,461)     $ 13,364,130
                                          =========================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                              $    48,393   $   111,551      $    746,706        $          -      $    906,650
   Commercial paper                                  912,246             -                 -                   -           912,246
   Other current liabilities                         294,642       167,201           (62,668)                  -           399,175
   Liabilities of discontinued operations                  -             -            64,245                                64,245
                                          -----------------------------------------------------------------------------------------
                                                   1,255,281       278,752           748,283                   -         2,282,316
                                          -----------------------------------------------------------------------------------------
Intercompany Accounts Payable                              -       101,345         2,147,777          (2,249,122)                -
                                          -----------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                                  (83,214)      298,062           909,281                   -         1,124,129
Other deferred credits and liabilities               534,521       112,004           964,387                   -         1,610,912
                                          -----------------------------------------------------------------------------------------
                                                     451,307       410,066         1,873,668                   -         2,735,041
                                          -----------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                        3,940,497       815,597         3,604,139          (4,465,523)        3,894,710
Preferred stock                                       19,700             -                 -                   -            19,700
Long-term debt                                     2,353,547       650,904         2,943,094          (1,528,816)        4,418,729
                                          -----------------------------------------------------------------------------------------
Total Capitalization                               6,313,744     1,466,501         6,547,233          (5,994,339)        8,333,139
                                          -----------------------------------------------------------------------------------------
Minority Interest in Consolidated Companies                -             -            13,634                   -            13,634
                                          -----------------------------------------------------------------------------------------
Total Liabilities & Capitalization               $ 8,020,332   $ 2,256,664      $ 11,330,595        $ (8,243,461)     $ 13,364,130
                                          =========================================================================================
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       159
<PAGE>


<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                   December 31, 2003
(In Thousands of Dollars)                             Guarantor          KEDLI   Other Subsidiaries     Eliminations   Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                 <C>              <C>             <C>               <C>             <C>
ASSETS
Current Assets
   Cash and temporary cash investments             $    97,567      $     1,554    $    104,237       $          -    $    203,358
   Accounts receivable, net                              3,298          209,151       1,068,066                  -       1,280,515
   Other current assets                                  3,250          136,018         649,988                  -         789,256
   Assets of discontinued operations                         -                -         114,196                            114,196
                                             --------------------------------------------------------------------------------------
                                                       104,115          346,723       1,936,487                  -       2,387,325
                                             --------------------------------------------------------------------------------------

Investments and others                               4,475,949            1,123         153,520         (4,382,027)        248,565
                                             --------------------------------------------------------------------------------------
Property
   Gas                                                       -        1,899,375       4,622,876                  -       6,522,251
   Other                                                     -                -       6,132,592                  -       6,132,592
   Accumulated depreciation and depletion                    -         (355,376)     (3,413,752)                 -      (3,769,128)
   Property of discontinued operations                       -                -           8,588                              8,588
                                             --------------------------------------------------------------------------------------
                                                             -        1,543,999       7,350,304                  -       8,894,303
                                             --------------------------------------------------------------------------------------

Intercompany Accounts Receivable                     3,105,571                -       1,274,283         (4,379,854)              -

Deferred Charges                                       374,076          237,870       2,498,043                  -       3,109,989

                                             --------------------------------------------------------------------------------------
Total Assets                                       $ 8,059,711      $ 2,129,715    $ 13,212,637       $ (8,761,881)   $ 14,640,182
                                             ======================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                                $   125,892      $   165,613    $    773,989       $          -    $  1,065,494
   Commercial paper                                    481,900                -               -                  -         481,900
   Other current liabilities                           129,168           21,149          72,365                  -         222,682
   Liabilities of discontinued operations                    -                -          82,204                             82,204
                                             --------------------------------------------------------------------------------------
                                                       736,960          186,762         928,558                  -       1,852,280
                                             --------------------------------------------------------------------------------------
Intercompany Accounts Payable                                -          116,197       2,679,091         (2,795,288)              -
                                             --------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                                    (48,059)         256,882       1,066,735                  -       1,275,558
Other deferred credits and liabilities                 532,062          136,747         968,814                  -       1,637,623
                                             --------------------------------------------------------------------------------------
                                                       484,003          393,629       2,035,549                  -       2,913,181
                                             --------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                          3,707,785          782,223       3,562,675         (4,382,027)      3,670,656
Preferred stock                                         83,568                -               -                  -          83,568
Long-term debt                                       3,047,395          650,904       3,497,215         (1,584,566)      5,610,948
                                             --------------------------------------------------------------------------------------
Total Capitalization                                 6,838,748        1,433,127       7,059,890         (5,966,593)      9,365,172
                                             --------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies                    -                -         509,549                  -         509,549
                                             --------------------------------------------------------------------------------------
Total Liabilities & Capitalization                 $ 8,059,711      $ 2,129,715    $ 13,212,637       $ (8,761,881)   $ 14,640,182
                                             ======================================================================================
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       160
<PAGE>


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
------------------------------------------------------------------------------------------------------------------------------------
                                                                                    Year Ended December 31, 2004
                                                          --------------------------------------------------------------------------
(In Thousands of Dollars)                                         Guarantor         KEDLI        Other Subsidiaries     Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>             <C>                   <C>               <C>
Operating Activities
   Net Cash (Used in) Provided by Operating Activities           $ (88,676)      $ 169,549             $  669,196        $  750,069
                                                          --------------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                  -        (108,658)              (641,671)         (750,329)
   Cost of removal                                                       -          (7,140)               (29,147)          (36,287)
   Proceeds from sale of property                                        -               -                 20,159            20,159
   Proceeds from sale of subsidiary stock                                -               -              1,001,142         1,001,142
                                                          --------------------------------------------------------------------------
Net Cash (Used in) Provided by Investing Activities                      -        (115,798)               350,483           234,685
                                                          --------------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                            33,406               -                      -            33,406
   Issuance (payment) of debt, net                                (269,654)              -               (170,745)         (440,399)
   Redemption of preferred stock                                    (8,483)              -                      -            (8,483)
   Net proceeds from sale/leaseback transaction                          -               -                382,049           382,049
   Common and preferred stock dividends paid                      (291,148)              -                      -          (291,148)
   Gain on interest rate swap                                       12,656               -                      -            12,656
   Dividend paid to parent                                         447,590         (40,000)              (407,590)                -
   Other                                                            27,623               -                  8,564            36,187
   Net intercompany accounts                                       619,831         (16,199)              (603,632)                -
                                                          --------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities                571,821         (56,199)              (791,354)         (275,732)
                                                          --------------------------------------------------------------------------

Net Increase in Cash and Cash Equivalents                        $ 483,145        $ (2,448)            $  228,325        $  709,022
Net Cash Flow from Discontinued Operations                               -               -                  9,593            9,593
Cash and Cash Equivalents at Beginning of Period                    97,567           1,554                104,237           203,358
                                                          --------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                       $ 580,712        $   (894)            $  342,155        $  921,973
                                                          ==========================================================================
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>





                                       161
<PAGE>


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Year Ended December 31, 2003
                                                           ------------------------------------------------------------------------
(In Thousands of Dollars)                                         Guarantor        KEDLI        Other Subsidiaries     Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>           <C>                   <C>               <C>
Operating Activities
Net Cash (Used in) Provided by Operating Activities              $ (547,516)    $ 164,496            $ 1,606,376       $ 1,223,356
                                                           ------------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                   -      (130,275)              (879,118)       (1,009,393)
   Cost of removal                                                        -        (1,710)               (29,393)          (31,103)
   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)     (116,862)              (825,308)         (997,170)
                                                           ------------------------------------------------------------------------
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)
    (Payment) issuance of debt                                     (133,797)            -                120,222           (13,575)
    Redemption of preferred stock                                         -             -                (14,293)          (14,293)
    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)              (739,407)         (180,184)
                                                           ------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents              $   9,259     $  (4,918)           $    41,661       $    46,002
Net Cash from Discontinued Operations                                     -             -                (13,261)          (13,261)
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            $   104,237       $   203,358
                                                           ========================================================================
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
---------------------------------------------------------------------------------------------------------------------------------
                                                                                  Year Ended December 31, 2002
                                                        -------------------------------------------------------------------------
(In Thousands of Dollars)                                    Guarantor         KEDLI          Other Subsidiaries     Consolidated
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>              <C>                    <C>             <C>
Operating Activities
   Net Cash (Used in) Provided by Operating Activities       $ (97,981)       $189,838               $ 655,806       $   747,663
                                                        -------------------------------------------------------------------------
Investing Activities
   Capital expenditures                                              -        (146,450)               (911,057)       (1,057,507)
   Other                                                             -             903                 151,358           152,261
   Cost of removal                                                   -            (883)                (26,548)          (27,431)
                                                        -------------------------------------------------------------------------
Net Cash (Used in) Investing Activities                              -        (146,430)               (786,247)         (932,677)
                                                        -------------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                        86,710               -                       -            86,710
   Issuance (payment) of debt, net                             327,247               -                 (35,603)          291,644
   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)                 39,389           188,742
                                                        -------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents         $  88,308        $  6,472               $ (91,052)      $     3,728
Net Cash Flow from Discontinued Operations                           -               -                  14,166            14,166
Cash and Cash Equivalents at Beginning of Period                     -               -                 152,723           152,723
                                                        -------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                   $  88,308        $  6,472               $  75,837       $   170,617
                                                        =========================================================================
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                                       162
<PAGE>



Note 15. Supplemental Gas and Oil Disclosures (Unaudited)

For  December  31,  2003 and 2002 the  following  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 and 34% in 2002. Gas and oil operations,  and reserves, were located in the
United  States  in  all  years.  As a  result  of  the  disposition  of  Houston
Exploration  and the  immateriality  of KeySpan's  ongoing gas  exploration  and
production activities  supplemental gas and oil disclosures are not required for
2004.

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

<TABLE>
<CAPTION>
Costs Incurred in Property Acquisition, Exploration and Development Activities
-----------------------------------------------------------------------------------------------
                                                       (In Thousands of Dollars)
-----------------------------------------------------------------------------------------------
At December 31,                                                   2003                  2002
-----------------------------------------------------------------------------------------------
<S>                                                             <C>                   <C>
Acquisition of properties -
     Unproved properties                                       $  61,484             $  14,600
     Proved properties                                           171,297                90,004
Exploration                                                       66,259                28,343
Development                                                      170,493               139,108
Asset retirement obligation                                       31,858                     -
-----------------------------------------------------------------------------------------------
Total costs incurred                                           $ 501,391             $ 272,055
-----------------------------------------------------------------------------------------------
</TABLE>

Costs included in development costs to develop proved  undeveloped  reserves for
the years  ended  December  31,  2003 and 2002  were  $49.4  million,  and $11.0
million, respectively.


Results of Operations from Gas and Oil Producing Activities*
-------------------------------------------------------------------------------
                                           (In Thousands of Dollars)
-------------------------------------------------------------------------------
At December 31,                                        2003              2002
-------------------------------------------------------------------------------
Revenues                                         $   497,948        $  356,233
-------------------------------------------------------------------------------
Production and lifting costs                          63,591            44,822
Shipping and handling costs                           10,388             9,450
Depletion                                            205,118           177,548
-------------------------------------------------------------------------------
Total expenses                                       279,097           231,820
-------------------------------------------------------------------------------
Income before taxes                                  218,851           124,414
Income taxes                                          76,598            42,519
-------------------------------------------------------------------------------
Results of operations                            $   142,253        $   81,895
-------------------------------------------------------------------------------
o    (Excluding corporate overhead and interest costs)


                                       163
<PAGE>


<TABLE>
<CAPTION>
Summary of Production and Lifting Costs
---------------------------------------------------------------------------------------------
                                                               (In Thousands of Dollars)
---------------------------------------------------------------------------------------------
At December 31,                                                       2003             2002
---------------------------------------------------------------------------------------------
<S>                                                                 <C>               <C>
Pumping, gauging and other labor                                   $ 10,975          $ 7,846
Compressors and other rental equipment                                5,136            4,135
Property taxes and insurance                                          7,155            6,801
Transportation                                                        2,329            2,131
Processing fees                                                       2,354            3,078
Workover and well stimulation                                         5,225            2,348
Repairs, maintenance and supplies                                     3,735            2,972
Fuel and chemicals                                                    3,109            2,582
Environmental, regulatory and other                                   7,614            3,307
Severance taxes                                                      15,959            9,622
---------------------------------------------------------------------------------------------
Total production and lifting costs                                 $ 63,591         $ 44,822
---------------------------------------------------------------------------------------------
</TABLE>


The gas and oil reserves  information  is based on estimates of proved  reserves
attributable  to the  interest  of  Seneca-Upshur  and KeySpan  Exploration  and
Production,  LLC as of December 31, 2004. For December 31, 2003 and 2002 the gas
and  oil  reserves   information   reflects  Houston   Exploration  and  KeySpan
Exploration and Production,  LLC. 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.


Reserve Quantity Information Natural Gas (MMcf)
--------------------------------------------------------------------------------
At December 31,                                        2003              2002
--------------------------------------------------------------------------------
Proved Reserves
   Beginning of year                                  614,734           585,659
   Revisions of previous estimates                    (32,433)          (15,324)
   Extensions and discoveries                         140,632           105,798
   Production                                        (100,130)         (107,507)
   Purchases of reserves in place                      89,380            48,777
   Sales of reserves in place                               -            (2,669)
--------------------------------------------------------------------------------
Proved reserves - End of year (1)                     712,183           614,734
Proved developed reserves
   Beginning of year                                  435,629           448,921
   End of Year (2)                                    488,012           435,629
--------------------------------------------------------------------------------

(1)  Includes  minority  interest of  318,417,  and  208,516,  in 2003 and 2002,
     respectively.

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


                                       164
<PAGE>


Crude Oil, Condensate and Natural Gas Liquids (MBbls)
-------------------------------------------------------------------------------
At December 31,                                        2003               2002
-------------------------------------------------------------------------------
Proved reserves
Beginning of Year                                       9,548           10,234
Revisions of previous estimates                        (3,542)              (5)
Extension and discoveries                                 117              342
Production                                             (1,514)          (1,025)
Purchases of reserves in place                          3,753              483
Sales of reserves in place                                  -             (481)
-------------------------------------------------------------------------------
Proved reserves - End of year (1)                       8,362            9,548
Proved developed reserves
Beginning of year                                       2,413            2,479
End of year (2)                                         4,273            2,413
-------------------------------------------------------------------------------

(1)  Includes   minority   interest  of  3,739  and  2,256  in  2003  and  2002,
     respectively.

(2)  Includes minority interest of 1,910 and 824 in 2003 and 2002, respectively.

The  standardized  measure of  discounted  future net cash flows was prepared by
applying  year-end  prices of gas and oil  adjusted for the effects of KeySpan's
hedging  program 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  Seneca-Upshur,  KeySpan  Exploration and Production LLC, or Houston
Exploration. 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
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                       <C>                    <C>
Future cash flows                                                                        $ 4,375,781            $ 2,951,622
Future costs-
Production                                                                                  (769,892)              (495,097)
Development                                                                                 (378,547)              (263,926)
----------------------------------------------------------------------------------------------------------------------------
Future net inflows before income tax                                                       3,227,342              2,192,599
Future income taxes                                                                         (853,425)              (559,853)
----------------------------------------------------------------------------------------------------------------------------
Future net cash flows                                                                      2,373,917              1,632,746
10% discount factor                                                                         (853,403)              (528,829)
----------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows (1)                             $ 1,520,514            $ 1,103,917
----------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Includes  minority  interest  of  $672,620  and  $361,435 in 2003 and 2002,
     respectively


                                       165
<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
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>                      <C>
 Standardized measure - beginning of year                                           $ 1,103,917             $   586,186
 Sales and transfers, net of production costs                                          (492,328)               (285,603)
 Net change in sales and transfer prices, net
      of production costs                                                               384,299                 589,632
 Extensions and discoveries and improved
      recovery, net of related costs                                                    434,311                 242,055
 Changes in estimated future development costs                                           (9,352)                 (6,453)
 Development costs incurred during the period
      that reduced future development costs                                              81,025                  42,075
 Revisions of quantity estimates                                                       (123,954)                (36,368)
 Accretion of discount                                                                  142,296                  68,986
 Net change in income taxes                                                            (236,551)               (215,369)
 Net purchases of reserves in place                                                     254,030                  99,741
 Sales of reserves in place                                                                   -                 (31,488)
 Changes in production rates (timing) and other                                         (17,179)                 50,523
------------------------------------------------------------------------------------------------------------------------
 Standardized measure - end of year                                                 $ 1,520,514             $ 1,103,917
------------------------------------------------------------------------------------------------------------------------
</TABLE>



<TABLE>
<CAPTION>
Average Sales Prices and Production Costs Per Unit
----------------------------------------------------------------------------------------------------------------
Year Ended December 31,                                                           2003              2002
----------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>               <C>
Average Sales Price*
     Natural gas ($/Mcf)                                                           5.23              3.16
     Oil, condensate and natural gas liquid ($/Bbl)                               28.26             24.06
Production cost per equivalent Mcf ($)                                             0.58              0.42
----------------------------------------------------------------------------------------------------------------
</TABLE>

*Represents  the cash price  received  which  excludes the effect of any hedging
transactions.





                                       166
<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, 2004.

<TABLE>
<CAPTION>
                                                                                       Quarter Ended
-----------------------------------------------------------------------------------------------------------------------------------
        (In Thousands of Dollars, Except Per Share Amounts)   3/31/2004      6/30/2004             9/30/2004         12/31/2004
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>             <C>                   <C>              <C>
Operating Revenue                                             2,510,592       1,277,806              975,544         1,886,524
Operating Income                                                487,627         122,158  (a)          87,613  (c)      237,872(e)
Earnings (loss) from continuing operations,
 less preferred stock dividends                                 246,636         128,485  (a)(b)      (30,133) (c)(d)   264,113(e)(f)
Earnings (loss) from discontinued operations (g)                   (401)            793              (87,006)          (64,434)
Earnings (loss) for common stock                                246,235         129,278             (117,139)          199,679
Basic earnings per common share from continuing operations
 less preferred stock dividends                                    1.54            0.81                (0.19)             1.64
Basic earnings per common share from discontinued operations       0.00            0.00                (0.54)            (0.40)
Basic earnings per common share                                    1.54            0.81                (0.73)             1.24
Diluted earnings per common share                                  1.53            0.80                (0.73)             1.23
Dividends declared                                                0.445           0.445                0.445             0.445
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(a) KeySpan's wholly owned gas exploration and production  subsidiaries recorded
a non-cash impairment charge of $48.2 million ($31.1 million after-tax) or $0.19
per share to recognize the reduced valuation of proved reserves.

(b) In June 2004,  KeySpan  exchanged  10.8  million  shares of common  stock of
Houston  Exploration for 100% of the stock of Seneca Upshur  Petroleum,  Inc. We
recorded a gain of $150.1  million  and were  required  to record  deferred  tax
expense of $44.1  million.  The net gain on the share exchange less the deferred
tax  provision  was $106  million or $0.66 per  share.  In April  2004,  KeySpan
recorded a gain of $22.8 million ($10.1  million  after-tax) or $0.06 per share,
resulting from the sale of 35.9% of our ownership interest in KeySpan Canada.

(c) KeySpan  recorded a $14.4  million  ($12.6  million  after-tax) or $0.08 per
share  non-cash  goodwill  impairment  charge  associated  with  our  continuing
investments in the Energy Services segment.

(d) In August 2004, we redeemed  approximately  $758 million of outstanding debt
and recorded a charge of $45.9 million  ($29.3  million  after-tax) or $0.18 per
share representing call premiums incurred on this redemption.

(e) In December 2004, we recorded a $26.5 million  ($18.8 million  after-tax) or
$0.12 per share non-cash impairment charge related to our 50% ownership interest
in Premier Transmission Pipeline.

(f) In November 2004,  KeySpan  decided to sell its remaining 6.6 million shares
of Houston  Exploration.  We recorded a gain of $179.6 million  ($116.8  million
after-tax)  or $0.73 per share.  In December  2004,  KeySpan sold its  remaining
interest in KeySpan  Canada.  We recorded a gain of $35.8 million ($24.7 million
after tax) or $0.15 per share.

(g) At December 31, 2004, KeySpan intended to sell a significant  portion of its
ownership  interest in certain  companies  within the Energy  Services  segment,
specifically those companies engaged in mechanical contracting activities.  As a
result, KeySpan recorded a loss in discontinued operations of $151.1 million, or
$0.94 per share. This loss reflects $139.9 million after-tax impairment charges,
which were recorded in the third and fourth  quarters,  and operating  losses at
$11.2 million.


                                       167
<PAGE>


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 Revenue                                                  2,423,482         1,307,366        1,032,532       1,772,144
Operating income                                                     455,082           139,087          112,205         341,255
Earnings (loss) from continuing operations less preferred stock
 dividends                                                           240,684  (a)       (7,089) (b)      13,407         173,223  (c)
Earnings (loss) from discontinued operations (e)                         946              (310)          (2,283)           (241)
Cumulative change in accounting principle                                174                 -                -         (37,625) (d)
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                              1.54             (0.05)            0.08            1.09
Basic earnings per common share from discontinued
 operations (a)                                                         0.00              0.00            (0.01)           0.00
Change in accounting principle                                          0.00              0.00             0.00            (0.24)
Basic earnings per common share                                         1.54             (0.05)            0.07            0.85
Diluted earnings per common share                                       1.53             (0.05)            0.07            0.84
Dividends declared                                                     0.445             0.445            0.445           0.445
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>



(a) In February 2003, we reduced our ownership  interest in Houston  Exploration
from 66% to 56% following the repurchase,  by Houston Exploration,  of 3 million
shares of stock owned by KeySpan. This transaction resulted in an after-tax gain
of $19.0 million or $0.12 per share.

(b) In May 2003,  we monetized 39% of our interest in KeySpan  Canada,  and sold
our 20% interest in Taylor NGL LP, a company  that owns and operates  extraction
plants in  Canada.  The  transactions  resulted  in an  after-tax  loss of $34.1
million or $0.22 per share.

(c) In  December  2003,  we sold our 24.5%  interest in Phoenix  Natural  Gas, a
natural gas distribution  business in Northern  Ireland.  KeySpan  recognized an
after-tax gain on the sale of $16.0 million per share or $.10 per share.

(d)  As  a  result  of  the   implementation  of  FASB   Interpretation  No.  46
"Consolidation  of  Variable  Interest  Entities",  in  December  2003,  KeySpan
consolidated the Ravenswood  Master Lease.  KeySpan recorded a cumulative effect
change in accounting  principle of $37.6 million or $0.23 per share,  related to
"catch-up" depreciation of the facility since its acquisition in June 1999.

(e) In December 2004,  KeySpan  reflected  certain Energy Services  companies as
discontinued.  Amounts  for each of the  quarters  in the year  2003  have  been
restated to reflect this presentation.


                                       168


<PAGE>



            REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Shareholders and Board of Directors of KeySpan Corporation


We  have  audited  the   accompanying   Consolidated   Balance  Sheets  and  the
Consolidated Statement of Capitalization of KeySpan Corporation and subsidiaries
(the  "Company") as of December 31, 2004 and 2003, 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, 2004.  Our audits also
included the consolidated  financial statement schedule included in the Index in
Item 15. These financial statements and the financial statement schedule are the
responsibility of the Company's management.  Our responsibility is to express an
opinion on the financial  statements and the financial  statement schedule based
on our audits.

We conducted our audits in accordance  with the standards of the Public  Company
Accounting Oversight Board (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,  such consolidated  financial  statements present fairly, in all
material   respects,   the  financial   position  of  KeySpan   Corporation  and
subsidiaries  as of  December  31,  2004  and  2003,  and the  results  of their
operations  and their cash flows for each of the three years in the period ended
December 31, 2004, in conformity with accounting  principles  generally accepted
in the  United  States  of  America.  Also  in our  opinion,  such  consolidated
financial  statement  schedule,   when  considered  in  relation  to  the  basic
consolidated  financial  statements  taken as a whole,  presents  fairly  in all
material respects, the information set forth therein.

As discussed in Note 1(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," 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-Transaction   and   Disclosure"  and  SFAS  No.  143,
"Accounting for Asset Retirement Obligations",  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).

We have also  audited,  in accordance  with the standards of the Public  Company
Accounting  Oversight Board (United States),  the effectiveness of the Company's
internal control over financial  reporting as of December 31, 2004, based on the
criteria  established in Internal  Control--Integrated  Framework  issued by the
Committee of Sponsoring  Organizations of the Treadway Commission and our report
dated  February  28,  2005,  expressed an  unqualified  opinion on  management's
assessment of the effectiveness of the Company's internal control over financial
reporting  and an  unqualified  opinion on the  effectiveness  of the  Company's
internal control over financial reporting.


/s/DELOITTE & TOUCHE LLP
February 28, 2005
New York, New York


                                       169
<PAGE>


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

None

Item 9A. Controls and Procedures

We maintain  disclosure  controls and  procedures (as defined under Exchange Act
Rule  13a-15(e))  that are  designed to ensure that  information  required to be
disclosed  by us in the  reports  we file or submit  under 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
our Chief Executive  Officer and Chief  Financial  Officer,  as appropriate,  to
allow timely decisions  regarding  required  disclosure.  Any control system, no
matter how well designed and operated,  can provide only reasonable assurance of
achieving the desired control objectives. Our management,  under the supervision
and with the  participation  of our Chief Executive  Officer and Chief Financial
Officer,  has  evaluated  the  effectiveness  of  our  disclosure  controls  and
procedures  as of  December  31,  2004.  Based upon that  evaluation,  our Chief
Executive  Officer and Chief  Financial  Officer  concluded  that the design and
operation  of  our  disclosure   controls  and  procedures  provided  reasonable
assurance  that  the  disclosure   controls  and  procedures  are  effective  to
accomplish their objectives.

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,  which has  materially
affected,  or is reasonably  likely to  materially  affect,  KeySpan's  internal
control over financial reporting.

Management's Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal
control over financial reporting (as defined under Exchange Act Rule 13a-15(f)).
KeySpan's  internal  control  over  financial  reporting  is designed to provide
reasonable  assurance  regarding the reliability of financial  reporting and the
preparation  of financial  statements for external  purposes in accordance  with
generally accepted accounting principles.

Because of its inherent  limitations,  internal control over financial reporting
may not prevent or detect misstatements,  errors or fraud. Also,  projections of
any evaluation of  effectiveness  to future periods are subject to the risk that
controls may become  inadequate  because of changes in  conditions,  or that the
degree of or compliance with the policies or procedures may deteriorate.

Under the  supervision  and with  participation  of  KeySpan's  Chief  Executive
Officer and Chief Financial Officer,  our management  assessed the effectiveness
of our internal  control over  financial  reporting as of December 31, 2004.  In
making  this  assessment,  our  management  used the  criteria  set forth by the
Committee of Sponsoring  Organizations of the Treadway  Commission ("COSO") in a
report entitled Internal Control-Integrated Framework. Our management concluded,
as of  December  31,  2004,  that  KeySpan's  internal  control  over  financial
reporting is effective based on the COSO criteria.

Our independent  registered public  accounting firm,  Deloitte & Touche LLP, has
issued their report on  management's  assessment of KeySpan's  internal  control
over financial reporting as of December 31, 2004, which is included herein.


                                      170
<PAGE>


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of KeySpan Corporation:

We  have  audited   management's   assessment,   included  in  the  accompanying
Management's Report on Internal Control over Financial  Reporting,  that KeySpan
Corporation and  subsidiaries  (the  "Company")  maintained  effective  internal
control over  financial  reporting  as of December  31, 2004,  based on criteria
established in Internal Control--Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. The Company's management is
responsible for maintaining  effective internal control over financial reporting
and for its assessment of the  effectiveness  of internal control over financial
reporting.   Our  responsibility  is  to  express  an  opinion  on  management's
assessment and an opinion on the effectiveness of the Company's internal control
over financial reporting based on our audit.

We conducted  our audit in accordance  with the standards of the Public  Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain  reasonable  assurance  about whether  effective
internal  control  over  financial  reporting  was  maintained  in all  material
respects. Our audit included obtaining an understanding of internal control over
financial reporting,  evaluating management's assessment, testing and evaluating
the design and operating  effectiveness of internal control, and performing such
other  procedures as we considered  necessary in the  circumstances.  We believe
that our audit provides a reasonable basis for our opinions.

A company's internal control over financial  reporting is a process designed by,
or under the  supervision  of, the company's  principal  executive and principal
financial officers, or persons performing similar functions, and effected by the
company's  board of  directors,  management,  and  other  personnel  to  provide
reasonable  assurance  regarding the reliability of financial  reporting and the
preparation  of financial  statements for external  purposes in accordance  with
generally  accepted  accounting  principles.  A company's  internal control over
financial  reporting  includes those policies and procedures that (1) pertain to
the  maintenance  of records that, in reasonable  detail,  accurately and fairly
reflect the  transactions  and  dispositions  of the assets of the company;  (2)
provide  reasonable  assurance  that  transactions  are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting  principles,  and that receipts and  expenditures  of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of  unauthorized  acquisition,  use, or  disposition  of the company's
assets that could have a material effect on the financial statements.


                                      171
<PAGE>


Because  of  the  inherent   limitations  of  internal  control  over  financial
reporting,  including  the  possibility  of  collusion  or  improper  management
override of controls,  material  misstatements  due to error or fraud may not be
prevented or detected on a timely basis. Also,  projections of any evaluation of
the  effectiveness  of the internal  control over financial  reporting to future
periods are subject to the risk that the controls may become inadequate  because
of changes in conditions,  or that the degree of compliance with the policies or
procedures may deteriorate.

In our opinion,  management's  assessment that the Company maintained  effective
internal  control over  financial  reporting as of December 31, 2004,  is fairly
stated, in all material respects,  based on the criteria established in Internal
Control--Integrated   Framework   issued   by  the   Committee   of   Sponsoring
Organizations  of the  Treadway  Commission.  Also in our  opinion,  the Company
maintained, in all material respects,  effective internal control over financial
reporting as of December 31, 2004, based on the criteria established in Internal
Control--Integrated   Framework   issued   by  the   Committee   of   Sponsoring
Organizations of the Treadway Commission.

We have also  audited,  in accordance  with the standards of the Public  Company
Accounting   Oversight  Board  (United  States),   the  Consolidated   financial
statements  and  financial  statement  schedule  as of and  for the  year  ended
December  31,  2004,  of the  Company  and our report  dated  February  28, 2005
expressed an  unqualified  opinion on those  financial  statements and financial
statement schedule.

/s/DELOITTE & TOUCHE LLP
February 28, 2005
New York, New York

                                      172


<PAGE>


Item 9B.    Other Information

The following  disclosures would otherwise have been filed on Form 8-K under the
heading "Item 1.01 - Entry into a Material Definitive Agreement".

On February 24, 2005,  following  the  recommendation  of the  Compensation  and
Management Development Committee (the "Compensation Committee"), KeySpan's Board
of Directors set the 2005 annual base  salaries for Robert B. Catell,  Robert J.
Fani,  Wallace P. Parker Jr., Steven L. Zelkowitz and Gerald  Luterman,  each of
whom is a KeySpan  named  executive  officer.  Such 2005  base  salaries  are as
follows:  Mr. Catell - $1,075,000,  Mr. Fani - $734,000,  Mr. Parker - $587,000,
Mr. Zelkowitz - $545,000,  and Mr. Luterman - $467,000.  For further information
regarding executive compensation, see "Item 11. Executive Compensation," herein.

In  December   2004,   the  Board   approved  the   compensation   formulas  for
performance-based  incentive  awards that may be paid to our executive  officers
for the fiscal year ending  December 31, 2005 ("Fiscal  2005") under the KeySpan
Corporate   Annual   Incentive   Compensation   Plan  (the  "Corporate   Plan").
Performance-based incentive awards as a percentage of cumulative base salary are
based upon earnings per share,  cash flow,  business unit  operating  income,  a
diversity  initiative,  customer  satisfaction  and other  individual  strategic
initiatives.  Award amounts will be calculated for each participant based on the
attainment  of the  indicated  financial  and  performance  measures  and may be
adjusted by the Compensation  Committee at its discretion.  For Fiscal 2005, the
performance-based  target award levels for each of the named executive  officers
have been increased.  Further information  regarding the target award levels for
Fiscal 2005 is contained in Exhibit  10.20-b filed herewith and  incorporated by
reference herein.

Also in December  2004, the  Compensation  Committee  approved the  compensation
formulas  for  performance-based  equity  awards  that  may  be  granted  to our
executive  officers  for Fiscal  2005 under the  KeySpan  Long-Term  Performance
Incentive  Compensation  Plan (the  "Long-Term  Incentive  Plan").  Target award
levels have been  modified  to align  closer with  industry  benchmarks  at 50th
percentile  levels.  Equity awards  granted under the Long-Term  Incentive  Plan
include a cumulative  three-year total shareholder  return ("TSR") goal. The TSR
goal  measures  the total  return  to  shareholders  of  KeySpan  Common  Stock,
including  price  appreciation  and  dividends.  KeySpan's  performance  will be
measured  against the S&P Utility  Group over a three-year  performance  period,
with the goal for KeySpan's TSR to be at or above the median of those  companies
comprising the group. For Fiscal 2005, the performance-based target award levels
for each of the named executive officers have been modified. Further information
regarding  the  target  award  levels for Fiscal  2005 is  contained  in Exhibit
10.22-b filed herewith and incorporated by reference herein.

For the fiscal year ending  December 31, 2004,  the Corporate  Plan provided for
award  opportunities to the named executive  officers with performance  criteria
based upon earnings per share,  cash flow,  business unit  operating  income,  a
diversity  initiative,  customer  satisfaction  and other  individual  strategic
initiatives. Based upon actual 2004 performance, an award payout for each of the
named  executive  officers was  approved by the Board on February  24, 2005,  as
follows:  Mr. Catell - $1,047,344,  Mr. Fani - $545,574,  Mr. Parker - $361,903,
Mr. Zelkowitz - $372,769, and Mr. Luterman - $262,355.


                                       173
<PAGE>


With respect to the Long Term Incentive  Plan awards,  on February 24, 2005, the
Compensation  Committee approved grants to the named executive officers based on
actual 2004 performance as follows:  Mr. Catell - 80,700 performance shares; Mr.
Fani - 125,800  non-qualified  stock options and 16,300 performance  shares; Mr.
Parker - 88,600  non-qualified  stock options and 11,400 performance shares; Mr.
Zelkowitz - 88,600  non-qualified  stock options and 11,400 performance  shares;
and  Mr.  Luterman  -  54,800  non-qualified  stock  options,  5,000  shares  of
restricted stock and 7,100 performance shares.

The options shall vest pro-rata over a five-year period with a ten year exercise
period from the date of grant.  Vesting will  accelerate  in the third year upon
achievement  of  KeySpan's  cumulative  three-year  TSR  goal.  In the  event of
retirement,  the options shall vest pro-rata  using the number of full months of
employment from the grant date to retirement, divided by 36 months.

With respect to the performance  shares,  at threshold  performance,  50% of the
award  shall be earned;  at target,  100% of the award  shall be earned;  and at
maximum,  150%  of the  award  shall  be  earned.  If  the  threshold  level  of
performance is not achieved all shares granted shall be forfeited.  In the event
of  retirement,  performance  shares  shall be  distributed  based upon  results
achieved at the end of the performance  period and pro-rated through the date of
retirement.

On February 25, 2005,  KeySpan  entered into an  employment  agreement  with Mr.
Catell  relating to his services as Chairman and Chief  Executive  Officer.  The
employment  agreement  supersedes all prior  agreements  between the parties and
provides for, among other things,  an extension of Mr. Catell's  employment term
until July 31, 2006 (or,  in the event of a change of  control,  until two years
following  the  consummation  of the  transaction  resulting  in such  change of
control),  a  minimum  annual  base  salary,  as  well as  participation  in the
Company's annual and long term incentive compensation plans. Upon termination of
employment for any reason other than cause, death or disability, Mr. Catell will
be entitled to payment of certain compensation accruable through the term of the
agreement.  A copy of Mr.  Catell's  employment  agreement is filed  herewith as
Exhibit 10.10 and incorporated herein by reference.

On February  25,  2005,  subsidiaries  of KeySpan  entered into a Share Sale and
Purchase  Agreement  with BG Energy  Holdings  Limited and Premier  Transmission
Financing  plc  ("PTF"),  pursuant  to which  all of the  outstanding  shares of
Premier are to be  purchased  by PTF.  It is  expected  that the sale of our 50%
interest in Premier will result in proceeds of approximately  $42.5 million.  It
is anticipated that the closing of this transaction will occur before the end of
the second quarter.


The following  disclosure  would otherwise have been filed on Form 8-K under the
heading "Item 5.02 - Departure of Directors or Principal  Officers;  Election of
Directors; Appointment of Principal Officers."

On  February  24,  2005 Mr.  Bodanza was elected by the Board to serve as Senior
Vice President,  Regulatory  Affairs and Asset  Optimization  effective March 1,
2005.  Mr.  Bodanza  previously  served  as Chief  Accounting  Officer.  Also on
February 24, 2005,  the Board  elected  Theresa A. Balog as Vice  President  and
Chief Accounting  Officer of KeySpan  Corporation,  effective March 1, 2005. Ms.


                                       174
<PAGE>


Balog, age 43, 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.


                                    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 29,
2005 (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
"Compliance  with  Section  16(a) of the  Exchange  Act"  contained in the Proxy
Statement, which information is incorporated herein by reference thereto.

Item 11. Executive Compensation

The information  required by this item is 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 in 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 herein by reference thereto.

Item 14. Principal Accountant Fees and Services

The information  required by this item is set forth under the caption  "Proposal
2.  Ratification  of  Deloitte & Touche  LLP as  Independent  Registered  Public
Accounting  Firm,"  "Fiscal Year 2004 Audit Firm Fee Summary" and "Report of the
Audit  Committee" in the Proxy  Statement,  which  information  is  incorporated
herein by reference thereto.


                                       175
<PAGE>


Item 15. Exhibits and Financial Statement Schedules


(a)  Required Documents

1.   Financial Statements

The following  consolidated financial statements of KeySpan and its subsidiaries
and Reports of the Independent Registered Public Accounting Firm are included in
Item 8 and are filed as part of this Report:

o    Consolidated  Statement of Income for the year ended December 31, 2004, the
     year ended December 31, 2003, and the year ended December 31, 2002

o    Consolidated Statement of Retained Earnings for the year ended December 31,
     2004,  the year ended  December 31, 2003,  and the year ended  December 31,
     2002

o    Consolidated Balance Sheet at December 31, 2004 and December 31, 2003

o    Consolidated  Statement of Capitalization at December 31, 2004 and December
     31, 2003

o    Consolidated  Statement of Cash Flows for the year ended December 31, 2004,
     the year ended December 31, 2003, and the year ended December 31, 2002

o    Consolidated  Statement of Comprehensive Income for the Year ended December
     31, 2004,  the year ended December 31, 2003 and the year ended December 31,
     2002

o    Notes to Consolidated Financial Statements

o    Reports of the Independent Registered Public Accounting Firm



                                       176
<PAGE>


2.   Financial Statement Schedules

Consolidated Schedule of Valuation and Qualifying Accounts for the year ended
December 31, 2004, the year ended December 31, 2003, and the year ended December
31, 2002.

<TABLE>
                  SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
                            Column A                    Column B        Column C            Column D       Column E
                                                                       Additions
-----------------------------------------------------------------------------------------------------------------------
                          Descriptions                 Balance at      Charged to                          Balance at
                                                      Beginning of      costs and             Net            End of
                                                         Period         expenses           Deductions         Period
-----------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>             <C>                    <C>            <C>
Twelve Months Ended December 31, 2004
-------------------------------------
     Deducted from asset accounts:
          Allowance for doubtful accounts*         $    75,671     $   74,089           $    81,964       $   67,796

     Additions to liability accounts:
          Reserve for injury and damages           $     9,370     $        -           $         -       $    9,370
          Reserve for environmental expenditures   $   294,691     $        -           $    37,902       $  256,789

Twelve Months Ended December 31, 2003
-------------------------------------
     Deducted from asset accounts:
          Allowance for doubtful accounts*         $    60,111     $   82,120           $    66,560       $   75,671

     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           $    71,127       $   60,111

     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
</TABLE>
*Reflects discontinued operations

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

(b)         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.

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)


                                       177
<PAGE>


3.2       By-Laws  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 7.625%
          notes  issued  on  November  20,  2000  (filed as  Exhibit  4-c to the
          Company's Form 8-K on November 20, 2000)

4.1-c     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)

4.2-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. and Citibank,  N.A., as co-syndication agents, The Bank
          of New York and The Royal Bank of Scotland  plc,  as  co-documentation
          agents,  and JPMorgan  Chase Bank,  as  administrative  agent for $640
          million,  dated as of June  30,  2004  (filed  as  Exhibit  4.1 to the
          Company's Form 10-Q for the quarterly period ended June 30, 2004)

4.4-a     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 JP 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)


                                       178
<PAGE>


4.4-b     First  Amendment to Credit  Agreement  dated as of June 27, 2003 among
          KeySpan   Corporation,   the  several   Lenders,   Citibank  N.A.,  as
          Syndication Agent, The Bank of New York and The Royal Bank of Scotland
          plc,  as   co-documentation   agents,  and  JPMorgan  Chase  Bank,  as
          administrative  agent to reduce the amount  from $850  million to $660
          million,  dated as of June  25,  2004  (filed  as  Exhibit  4.2 to the
          Company's Form 10-Q for the quarterly period ended June 30, 2004)

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)

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)


                                       179
<PAGE>


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)

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)


                                       180
<PAGE>


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 (filed as Exhibit 4.14-a to the Company's
          Form 10-K for the year ended December 31, 2003)

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  (filed  as  Exhibit  4.14-b  to  the
          Company's Form 10-K for the year ended December 31, 2003)

4.14-c    Guaranty,  dated as of November 26, 2003, from KeySpan  Corporation to
          the Suffolk  County  Industrial  Development  Agency (filed as Exhibit
          4.14-c to the  Company's  Form 10-K for the year  ended  December  31,
          2003)

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 (filed as Exhibit 4.15-a to the Company's Form 10-K
          for the year ended December 31, 2003)

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 (filed as Exhibit 4.15-b to the Company's Form 10-K
          for the year ended December 31, 2003)


                                       181
<PAGE>


4.15-c    Guaranty,  dated as of November 26, 2003, from KeySpan  Corporation to
          the Nassau  County  Industrial  Development  Agency  (filed as Exhibit
          4.14-c to the  Company's  Form 10-K for the year  ended  December  31,
          2003)

4.16      Indenture,  dated as of December 1, 1989,  between  Boston Gas Company
          and The Bank of New York,  as 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 quarterly
          period ended June 30, 1990)

4.25      Letter of Credit and Reimbursement Agreement,  dated December 9, 2003,
          by and between KeySpan  Generation LLC and Royal Bank of Scotland Bank
          PLC (filed as  Exhibit  4.34 to the  Company's  Form 10-K for the year
          ended December 31, 2003)


                                       182
<PAGE>


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)

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)


                                       183
<PAGE>


10.8** *  Cash Compensation for Non-Management Directors of KeySpan

10.9** *  Base Salaries of Named  Executive  Officers of KeySpan in effect as of
          February 24, 2005

10.10** * Employment  Agreement,   dated  February  24,  2005,  between  KeySpan
          Corporation and Robert B. Catell

10.11**   Employment  Agreement,  dated  January 1, 2005,  between  KeySpan  and
          Anthony Sartor (filed as Exhibit 10.01 to the Company's Form 8-K dated
          as of January 4, 2005)

10.12**   Supplemental  Retirement  Agreement,  dated  January 1, 2005,  between
          KeySpan and Anthony  Sartor (filed as Exhibit 10.12 to Company's  Form
          8-K dated as of January 4, 2005)

10.13**   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)

10.14**   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)

10.15**   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)

10.16**   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)

10.17**   Directors'  Deferred  Compensation Plan effective April 2003 (filed as
          Exhibit 10.16 to the Company's  Form 10-K for the year ended  December
          31, 2003)

10.18**   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)

10.19**   Officers' Deferred Stock Unit Plan of 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)


                                       184
<PAGE>


10.20-a** 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-b** * Corporate Annual Incentive  Compensation  Plan Target Performance
            Award Level for Fiscal 2005

10.21**   Senior  Executive  Change of Control  Severance  Plan  effective as of
          October  29,  2003  (filed as Exhibit  10.20 to the  Company's  Annual
          Report on Form 10-K for the year ended December 31, 2003)

10.22-a** 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-b** * KeySpan's  Long-Term  Performance  Incentive   Compensation  Plan
            Target Performance Award Level for Fiscal 2005

10.23     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)

10.24     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)

10.25     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)

10.26     KeySpan  Guaranty,  dated  May  25,  2004,  relating  to  the  250  MW
          Ravenswood  expansion  plant (filed as Exhibit  10.1 to the  Company's
          Form 10-Q for the quarterly period ended June 30, 2004)

10.27     Facility  Lease  Agreement,  dated  as of May  25,  2004,  between  SE
          Ravenswood Trust, a Delaware statutory trust, and  KeySpan-Ravenswood,
          LLC  relating  to the 250 MW  Ravenswood  expansion  plant  (filed  as
          Exhibit 10.2 to the Company's Form 10-Q for the quarterly period ended
          June 30, 2004)

10.28     Site Lease and Easement  Agreement,  dated as of May 25, 2004, between
          KeySpan-Ravenswood, LLC and SE Ravenswood Trust relating to the 250 MW
          Ravenswood  expansion  plant (filed as Exhibit  10.3 to the  Company's
          Form 10-Q for the quarterly period ended June 30, 2004)

10.29     Site Sublease,  dated as of May 25, 2004,  between SE Ravenswood Trust
          and  KeySpan-Ravenswood,   LLC  relating  to  the  250  MW  Ravenswood
          expansion  plant (filed as Exhibit 10.4 to the Company's Form 10-Q for
          the quarterly period ended June 30, 2004)


                                       185
<PAGE>


10.30     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)

10.31     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)

10.32     Distribution  Agreement,  dated June 2, 2004, by and among The Houston
          Exploration  Company,  Seneca-Upshur  Petroleum,  Inc.,  THEC Holdings
          Corp.  and KeySpan  Corporation  (filed as Exhibit 99.2 to The Houston
          Exploration Company's Form 8-K dated as of June 3, 2004)

10.33     Asset Contribution Agreement,  dated June 2, 2004, between The Houston
          Exploration  Company  and  Seneca-Upshur  Petroleum,  Inc.  (filed  as
          Exhibit 99.3 to The Houston Exploration Company's Form 8-K dated as of
          June 3, 2004)

10.34     Tax Matters  Agreement,  dated June 2, 2004,  by and among The Houston
          Exploration  Company,  Seneca-Upshur  Petroleum,  Inc.,  THEC Holdings
          Corp.  and KeySpan  Corporation  (filed as Exhibit 99.4 to The Houston
          Exploration Company's Form 8-K dated as of June 3, 2004).

10.35*    Purchase  Agreement,  dated January 28, 2005,  among Robert B. Snyder,
          Frank J. Sullivan, Robert B. Snyder, Jr., Philip J. Andreoli,  William
          J. McKean,  Binsky & Snyder,  LLC,  Binsky & Snyder  Service,  LLC and
          KeySpan Business Solutions, LLC

10.36*    Purchase Agreement,  dated February 11, 2005, among WDF Holding Corp.,
          WDF, Inc. and KeySpan Business Solutions, LLC

10.37*    Share Sale and  Purchase  Agreement  dated  February  25, 2005 with BG
          Energy  Holdings  Limited and Premier  Transmission  Financing  Public
          Limited Company

14*       Code of Ethics (filed as Exhibit 14 to the Company's Form 10-K for the
          year ended December 31, 2003).

21*       Subsidiaries of the Registrant

23.1*     Consent  of  Deloitte  & Touche  LLP,  Independent  Registered  Public
          Accounting Firm

23.2*     Consent  of  Netherland,   Sewell  &  Associates,   Inc.,  Independent
          Petroleum Consultants


                                       186
<PAGE>


23.3*     Consent of Miller and Lents, Ltd., Independent Petroleum Consultants

24.1*     Power of Attorney  executed by Andrea S.  Christensen  on February 24,
          2005

24.2*     Power of Attorney executed by Robert J. Fani on February 24, 2005

24.3*     Power of Attorney executed by Alan H. Fishman on February 24, 2005

24.4*     Power of Attorney executed by James R. Jones on February 24, 2005

24.5*     Power of Attorney executed by James L. Larocca on February 24, 2005

24.6*     Power of Attorney executed by Gloria C. Larson on February 24, 2005

24.7*     Power of Attorney executed by Stephen W. McKessy on February 24, 2005

24.8*     Power of Attorney executed by Edward D. Miller on February 24, 2005

24.9*     Power of Attorney executed by Vikki L. Pryor on February 24, 2005

24.10*    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


                                       187
<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
---------------------



Theresa A. Balog                    Vice President and
                                    Chief Accounting Officer

By:/s/Theresa A. Balog
   --------------------



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

            *
----------------------
Robert J. Fani                      Director

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


                                       188
<PAGE>


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

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

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

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

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

            *
--------------------
Vikki L. 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



                                      189