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

                   For the fiscal year ended December 31, 2005

                         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


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

     Indicate by check mark if the registrant is a well known  seasoned  issuer,
as defined in Rule 405 of the Securities Act.
                                                              X Yes  ___No

     Indicate by check mark if the  registrant  is not  required to file reports
pursuant to Section 13 or Section 15(d) of the Act.
                                                              ___Yes  X No

     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 (ss. 229.405 of this chapter) 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.

                                                              ___Yes  X No

     Indicate by check mark whether the registrant is a large accelerated filer,
or a non-accelerated filler.

Large accelerated filer X     Accelerated filer__     Non-accelerated filer__

     Indicate  by check mark  whether  the  registrant  is a shell  company  (as
defined in Rule 12b-2 of the Act).
                                                              ___Yes  X No

     The aggregate market value of the voting and non-voting  common equity held
by  non-affiliates  (174,014,400  shares) of the registrant  was  $7,150,251,696
based on the closing price of the New York Stock  Exchange on February 23, 2006,
of $41.09 per share.

     As of February 23, 2006,  there were  174,573,840  shares of common  stock,
$.01 par value, outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE

     The Proxy  Statement  dated on or about March 31, 2006 is  incorporated  by
reference into Part III, Items 10, 11, 12 and 13 hereof.

<PAGE>

<TABLE>
<CAPTION>
                               KEYSPAN CORPORATION
                               INDEX TO FORM 10-K
                                                                                                               Page
                                                                                                               ----
                                     PART I
                                     ------
<S>          <C>                                                                                               <C>
ITEM 1.       BUSINESS............................................................................................1
ITEM 1A       RISK FACTORS........................................................................................28
ITEM 1B       UNRESOLVED STAFF COMMENTS...........................................................................35
ITEM 2.       PROPERTIES..........................................................................................35
ITEM 3.       LEGAL PROCEEDINGS...................................................................................35
ITEM 4.       SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................................................35

                                     PART II
                                     -------

ITEM 5.       MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
              AND ISSUER PURCHASES OF EQUITY SECURITIES...........................................................36
ITEM 6.       SELECTED FINANCIAL DATA.............................................................................38
ITEM 7.       MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION................39
ITEM 7A.      QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..........................................98
ITEM 8.       FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........................................................95
         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS..........................................................104
         NOTE 1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.....................................................104
         NOTE 2.  BUSINESS SEGMENTS..............................................................................122
         NOTE 3.  INCOME TAX.....................................................................................127
         NOTE 4.  POSTRETIREMENT BENEFITS........................................................................128
         NOTE 5.  CAPITAL STOCK..................................................................................133
         NOTE 6.  LONG-TERM DEBT AND COMMERCIAL PAPER............................................................134
         NOTE 7.  CONTRACTUAL OBLIGATIONS, FINANCIAL GUARANTEES
                         AND CONTINGENCIES.......................................................................138
         NOTE 8.  HEDGING, DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUES......................................149
         NOTE 9.  GAS EXPLORATION AND PRODUCTION PROPERTY - DEPLETION............................................153
         NOTE 10.  ENERGY SERVICES- DISCONTINUED OPERATIONS......................................................154
         NOTE 11.  2006 LIPA SETTLEMENT..........................................................................156
         NOTE 12.  SUBSEQUENT EVENTS.............................................................................158
         NOTE 13.  KEYSPAN GAS EAST CORPORATION SUMMARY FINANCIAL DATA...........................................159
         NOTE 14.  SUPPLEMENTAL GAS AND OIL DISCLOSURES (UNAUDITED) .............................................165
         NOTE 15.  SUMMARY OF QUARTERLY INFORMATION (UNAUDITED) .................................................168
ITEM 9.       CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
              FINANCIAL DISCLOSURE...............................................................................171
ITEM 9A.      CONTROLS AND PROCEDURES............................................................................171
ITEM 9B.      OTHER INFORMATION..................................................................................175

                                    PART III
                                    --------

ITEM 10.      DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.................................................177
ITEM 11.      EXECUTIVE COMPENSATION.............................................................................177
ITEM 12.      SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
              RELATED STOCKHOLDER MATTERS........................................................................177
ITEM 13.      CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.....................................................177
ITEM 14.      PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 15.      EXHIBITS, FINANCIAL STATEMENT SCHEDULES ...........................................................177
</TABLE>



<PAGE>


                                     PART I
                                     ------

ITEM 1.  BUSINESS

                               CORPORATE OVERVIEW

KeySpan  Corporation  ("KeySpan")  is a member of the  Standard  and  Poor's 500
Index.  KeySpan is a New York corporation and a holding company under the Public
Utility Holding  Company Act of 2005 ("PUHCA  2005").  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. We also own, lease 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 operating subsidiaries are primarily involved in gas exploration
and production;  underground gas storage; liquefied natural gas ("LNG") storage;
retail electric  marketing;  large  energy-system  ownership,  installation  and
management;  service and  maintenance of energy  systems;  and  engineering  and
consulting  services.  We also  invest and  participate  in the  development  of
natural gas pipelines, electric generation and other energy-related projects.

Recent Developments
-------------------

On February 25, 2006,  Keyspan entered into an Agreement and Plan of Merger (the
"Merger   Agreement"),   with  National  Grid  PLC,  a  public  limited  company
incorporated  under the laws of England and Wales  ("Parent")  and National Grid
USA, Inc, a New York  Corporation  ("Merger Sub"),  pursuant to which Merger Sub
will merge with and into KeySpan (the "Merger"),  with KeySpan continuing as the
surviving  Company.  Pursuant to the Merger Agreement,  at the effective time of
the Merger,  each outstanding share of common stock, par value $.01 per share of
KeySpan (the  "Shares"),  other than shares owned by KeySpan,  shall be canceled
and  shall be  converted  into the  right to  receive  $42.00  in cash,  without
interest.

Consummation of the Merger is subject to various closing  conditions,  including
but not  limited  to the  satisfaction  or waiver of  conditions  regarding  the
receipt  of  requisite  regulatory  approvals  and the  adoption  of the  Merger
Agreement by the  stockholders  of KeySpan and the Parent.  Assuming  receipt or
waiver of the  foregoing,  it is currently  anticipated  that the Merger will be
consummated  in  early  2007.  Accordingly,   any  statements  contained  herein
concerning expectations,  beliefs, plans, objectives,  goals, strategies, future
events  or  performance   and  underlying   assumptions   are   "forward-looking
statements"  and do not take  into  account  the  occurrence  or  impact  of any
potential  strategic  transaction on the future operations,  financial condition
and cash flows of KeySpan.  However,  no assurance  can be given that the Merger
will occur, or, the timing of its completion.

At December 31, 2005,  KeySpan was a holding  company  under the Public  Utility
Holding  Company Act of 1935, as amended  ("PUHCA  1935").  In August 2005,  the
Energy  Policy Act of 2005 (the "Energy  Act") was enacted.  The Energy Act is a
broad energy bill that places an increased  emphasis on the production of energy
and promotes the development of new technologies and alternative  energy sources
and provides  tax credits to companies  that  produce  natural gas,  oil,  coal,
electricity  and  renewable  energy.  For KeySpan,  one of the more  significant
provisions  of the  Energy  Act was the  repeal  of  PUHCA  1935,  which  became
effective  on  February  8,  2006.  Since  that time,  the  jurisdiction  of the
Securities  and  Exchange   Commission  ("SEC")  over  certain  holding  company
activities,  including the regulation of our affiliate  transactions and service
companies,  has been  transferred  to the  jurisdiction  of the  Federal  Energy
Regulatory  Commission ("FERC") pursuant to PUHCA 2005. See "Regulation and Rate
Matters" for  additional  information  on the Energy Act and PUHCA 2005. 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.


                                       1
<PAGE>

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 business segments:  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 LIPA;  provide generating
capacity and, to the extent required,  energy conversion  services for LIPA from
our  approximately  4,200 megawatts ("MW") of generating  facilities  located on
Long  Island;  and  manage  fuel  supplies  for  LIPA to fuel  our  Long  Island
generating facilities.  The Electric Services segment also includes subsidiaries
that own, lease and operate the 2,200 MW Ravenswood electric generation facility
(the "Ravenswood Facility"),  located in Queens County in New York City, and the
250 MW combined cycle generating unit (the "Ravenswood  Expansion")  which began
full commercial operation in May 2004 (collectively, the Ravenswood Facility and
the Ravenswood  Expansion are referred to herein as the  "Ravenswood  Generating
Station" and have a total electric capacity of 2,450 MW). Moreover, subsidiaries
in this segment also provide  retail  marketing  of  electricity  to  commercial
customers.

The Energy  Services  segment  provides  energy-related  services  to  customers
primarily located within the Northeastern  United States, with concentrations in
the New York City and Boston  metropolitan  areas.  During  January and February
2005, we disposed of our ownership  interests in companies engaged in mechanical
contracting activities under this segment.

The Energy  Investments  segment  includes our gas  exploration  and  production
activities,  domestic  pipelines,  gas storage facilities and LNG facilities and
operations.

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 it 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.

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. You may also read
and copy any of these  documents  at the SEC's  public  reference  room at 100 F
Street, N.E., Washington,  D.C. 20549. Please call the SEC at 1-800-SEC-0330 for
further  information  on the public  reference  room.  Our SEC  filings are also
available to the public on the SEC's web site at www.sec.gov.


                                       2
<PAGE>


GAS DISTRIBUTION OVERVIEW

Our  gas  distribution  activities  are  conducted  by  our  six  regulated  gas
distribution  subsidiaries,  which operate in three states in the Northeast: New
York, Massachusetts and New Hampshire. We are the fifth largest gas distribution
company  in  the  United  States  and  the  largest  in  the   Northeast,   with
approximately  2.6 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
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.

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.  In New
York,  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.  In Massachusetts
and New Hampshire,  there are mandatory  capacity  assignment  programs in place
whereby  capacity is released to natural gas  marketers  on behalf of  customers
they  serve.  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.


                                       3
<PAGE>


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  a  utility  tariff  that  contains  a  weather
normalization  adjustment  that  significantly  offsets  variations  in firm net
revenues due to  fluctuations in normal  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.

New York Gas Distribution Systems - KEDNY and KEDLY 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 2,093 MDTH (one MDTH equals 1,000 DTH or 1 billion British Thermal
Units) of gas for a peak-day  during the 2005/06  winter season and that the gas
available to us on such a peak-day amounts to approximately 2,177 MDTH.


                                       4
<PAGE>


The highest daily throughput most recently experienced occurred on January 15,
2006 in which the demand of the firm New York customers was 1,654 MDTH, and the
average temperature was 20(degree)F. KEDNY and KEDLI have sufficient gas supply
available to meet the requirements of their firm gas customers for the 2005/06
winter season.

Our New York firm gas peak-day capability is summarized in the following table:

                                  MDTH    per   % of
Source                            day           Total
----------------------------------------------------------

Pipeline                          842           39%
Underground Storage               800           37%
Peaking Supplies                  535           24%
                                  ---           ---

Total                             2,177         100%
                                ==========    =========

Pipelines.  Our New York based gas distribution  utilities  purchase natural gas
for sale under  contracts  with suppliers of 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
2005/06  gas year,  approximately  73% of our New York  natural  gas  supply was
available from domestic sources and 27% from Canadian sources. We have available
under  firm  contract  842  MDTH per day of  year-round  and  seasonal  pipeline
transportation capacity. Our major providers of interstate pipeline capacity and
related   services   include:   Transcontinental   Gas  Pipe  Line   Corporation
("Transco"),  Texas Eastern  Transmission  Corporation  ("Tetco"),  Iroquois Gas
Transmission   System,  L.P.   ("Iroquois"),   Tennessee  Gas  Pipeline  Company
("Tennessee"),  Dominion Transmission Incorporated  ("Dominion"),  and Texas Gas
Transmission Company.

Underground  Storage.  In order to meet  winter  demand in our New York  service
territories,  we also have long-term contracts with Transco,  Tetco,  Tennessee,
Dominion,  Equitrans,  Inc.,  National  Fuel Gas Supply  Corporation  ("National
Fuel") and Honeoye  Storage  Corporation  ("Honeoye")  for  underground  storage
capacity of 60,766 MDTH and 800 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 LNG plants; (ii)
peaking supply contracts with dual-fuel power producers located in our franchise
areas;  and (iii) peaking supply  contracts with suppliers  located  outside our
franchise area. For the 2005/06 winter season, we have the capability to provide
maximum  peaking  supplies of 535 MDTH on  extremely  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 dual fuel power  producers
provide us with peak-day capacity of 140 MDTH and winter season  availability of
3,446 MDTH.

Gas Supply  Management.  We  currently  perform  our New  York-based  gas supply
management services internally.

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.


                                       5
<PAGE>


Combined  Gas  Supply  Portfolios.  Effective  November  1,  2005  the New  York
Department of Public Service authorized KEDNY and KEDLI to combine the planning,
management and utilization of their  respective gas supply  portfolios to enable
each  company  to serve  its  customers  more  reliably  and  cost  effectively.
Specifically,  these  companies plan the  acquisition  of  incremental  pipeline
capacity,  underground  storage, gas supply and peaking supply contracts to meet
projected  growth in firm customer demand on a combined  portfolio  basis.  This
approach  enables these companies to realize  synergies that would otherwise not
be attainable if they were to plan  independently  for the  development of their
respective  portfolios.  These two  companies,  by  virtue  of their  geographic
proximity,  complementary customer demand profiles and similar gas contracts are
able to add  incremental  capacity more  effectively  to meet expected  customer
demand growth by planning the portfolios on a combined basis.

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, 2006, 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.

New England Gas Distribution Systems - KEDNE 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.
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 England gas systems assumes
an average  temperature of -6(0)F in  Massachusetts  and -8(0)F in New Hampshire
for peak-day demand.  Under such criteria,  we estimate that the requirements to
supply our firm gas customers  would amount to  approximately  1,361 MDTH of gas
for a peak-day during the 2005/06 winter season and that the gas available to us
on such a peak-day  amounts to  approximately  1,420 MDTH.

The highest daily throughput most recently  experienced  occurred on January 15,
2006 in which the demand of the firm New England  customers (which includes both
firm sales and firm  transportation) was 1,015 MDTH, and the average temperature
was 15*F.  KEDNE has sufficient gas supply available to meet the requirements of
their firm gas customers for the 2005/06 winter season.


                                       6
<PAGE>


Our New England firm gas peak-day capability is summarized in the following
table:

                                MDTH           % of
Source                         per day         Total
---------------------------------------------------------

Pipeline                       500            35%
Underground Storage            248            18%
Peaking Supplies               672            47%
                               ---            ---

Total                          1,420          100%
                              =======        ======

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

Underground  Storage.  In order to meet winter demand in our New England service
territories,  we also have long-term contracts with Tetco, Tennessee,  Dominion,
National Fuel and Honeoye for  underground  storage  capacity of 23,280 MDTH and
248 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) local  production
plants  that store LNG and liquid  propane  until  vaporized,  which are located
strategically  across the service territory;  (ii) contracts for LNG storage and
delivery with our LNG subsidiary,  KeySpan LNG LP, located in Providence,  Rhode
Island; and (iii) Distrigas of Massachusetts located in Everett,  Massachusetts.
For the 2005/06 winter season, we have the capability to provide maximum peaking
supplies of 672 MDTH on extremely cold days.

Gas Supply  Management.  From April 1, 2002 through  March 31,  2005,  we had an
agreement  with Coral  Resources,  L.P.  ("Coral"),  a  subsidiary  of Shell Oil
Company, under which Coral assisted in the origination,  structuring,  valuation
and execution of energy-related  transactions on behalf of KEDNY and KEDLI. Upon
the  expiration  of this  agreement,  these  services  are  provided  by 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 has a three year
term expiring on March 31, 2006. A new three year agreement has been  negotiated
between Merrill Lynch and the  Massachusetts  KEDNE  utilities,  whereby Merrill
Lynch will assist in the  origination,  structuring,  valuation and execution of
energy related transactions for the Massachusetts  portfolio.  This agreement is
pending  approval by the  Massachusetts  Department  of  Telecommunications  and
Energy ("MADTE").  In New Hampshire,  these services will be provided by KeySpan
employees.


                                       7
<PAGE>


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.

For  additional  information  and for financial  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"
and Note 2 to the Consolidated Financial Statements, "Business Segments".

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.  The  Ravenswood  Generating  Station 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 a third party.

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  T&D  system  pursuant  to a  Management
Services  Agreement (the "1998 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 "1998 PSA");  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 "1998 EMA").
The 1998 MSA,  1998 PSA and 1998 EMA became  effective  on May 28,  1998 and are
collectively referred to herein as the "1998 LIPA Agreements."

On February 1, 2006,  KeySpan and LIPA  entered into (i) an amended and restated
Management  Services Agreement (the "2006 MSA"),  pursuant to which KeySpan will
continue to operate and  maintain  the electric T&D System owned by LIPA on Long
Island;  (ii) a new Option and  Purchase  and Sale  Agreement  (the "2006 Option
Agreement"),  which allows LIPA to purchase either or both of KeySpan's  Barrett
and Far Rockaway  generating stations and which replaces the Generation Purchase
Rights  Agreement (the "GPRA"),  pursuant to which LIPA had the option,  through
December  15, 2005,  to acquire  substantially  all of the  electric  generating
facilities  owned by KeySpan on Long Island;  and (iii) a  Settlement  Agreement
(the "2006  Settlement  Agreement")  resolving  outstanding  issues  between the
parties  regarding  the 1998  LIPA  Agreements.  The 2006 MSA,  the 2006  Option
Agreement and the 2006 Settlement Agreement are collectively  referred to herein
as the "2006 LIPA Agreements".  In the event LIPA exercises its rights under the
2006  Option  Agreement,  KeySpan  and LIPA will  enter  into an  operation  and
maintenance  agreement,  pursuant to which KeySpan would continue to operate the
subject generating units, as well as related amendments to the 1998 PSA and 1998
EMA.  The 2006 LIPA  Agreements  will  become  effective  as of January 1, 2006,
following receipt of all necessary  governmental  approvals,  which are pending.
The effectiveness of each of the 2006 LIPA Agreements is conditioned upon all of
the 2006 LIPA Agreements becoming effective.


                                       8
<PAGE>


Portions of our Electric  Services  business can be affected by seasonal weather
conditions  and  market  conditions.   The  majority  of  the  capacity  revenue
associated  with the Ravenswood  Generating  Station is realized  during the six
months between May and October of each year.  Energy and ancillary service sales
from our Ravenswood Generating Station are directly correlated to the demand for
electricity  and competition  from other  resources.  Typically,  the demand and
price for electricity increases during extreme temperature conditions.  However,
depending  on  the  availability  of  alternative  competitive  supply,  extreme
temperature  conditions  may not  result  in  increased  revenue.  As a  result,
fluctuations  in  weather  and  competitive  supply  between  years  may  have a
significant  effect on our  results  of  operations  for our  Electric  Services
business.

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 Note 7 to the  Consolidated  Financial
Statements, "Contractual Obligations, Financial Guarantees and Contingencies."

In  2004,  we  completed  construction  of the  Ravenswood  Expansion,  a 250 MW
combined cycle generating unit at the Ravenswood  Facility,  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 Generating Station sells capacity,  energy and ancillary services
into the New York Independent  System Operator  ("NYISO")  electricity market at
market-based  rates,  subject to mitigation.  The Ravenswood  Generating Station
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 Ravenswood Generating Station and our New York City Operations

Currently, the NYISO's New York City local reliability rules require that 80% of
the  electric  capacity  needs  of  New  York  City  be  provided  by  "in-City"
generators.  On February 9, 2006, the NYISO  Operating  Committee  increased the
"in-City" generator  requirement to 83% beginning in May 2006 through the period
ending on April 2007, based in part on the statewide  reserve margin of 118% set
by the New York State Reliability  Council.  On February 16, 2006, an appeal was
filed with the NYISO  Management  Committee  requesting  that the  February  9th
decision be rejected and that the "in-City" requirement be increased to a larger
percentage  than 83%. A vote on this  appeal is  expected  to occur at the NYISO
Management Committee meeting scheduled for February 28, 2006.


                                       9
<PAGE>


Our Ravenswood  Generating  Station is an "in-City"  generator.  As the electric
infrastructure  in New York City and the  surrounding  areas continues to change
and evolve and the demand for electric power increases,  the "in-City" generator
requirement  could be further  modified.  Construction of new  transmission  and
generation  facilities may cause significant  changes to the market for sales of
capacity,  energy and ancillary services from our Ravenswood Generating Station.
Recently 500 MW of capacity came on line and it is anticipated  that another 500
MW of new capacity may be available during 2006 as a result of the completion of
an in-City generation project currently under construction.  We cannot, however,
be certain as to when the new power plant will be in  operation or the nature of
future New York City energy,  capacity or ancillary services market requirements
or design.

KeySpan  continues  to believe that New York City  represents a strong  capacity
market and has entered into an International Swap Dealers  Association  ("ISDA")
Master  Agreement for a fixed for float  unforced  capacity  financial swap (the
"Swap  Agreement")  with Morgan Stanley  Capital Group Inc.  ("Morgan  Stanley")
dated as of January 18, 2006. The Swap Agreement has a three year term beginning
May 1, 2006,  (assuming a condition to effectiveness  has been satisfied by such
date). The notional quantity is 1,800,000kW (the "Notional Quantity") of In-City
Unforced Capacity and the fixed price is $7.57/kW-month ("Fixed Price"), subject
to adjustment upon the occurrence of certain events. Settlement would occur on a
monthly basis based on the In-City  Unforced  Capacity  price  determined by the
relevant New York  Independent  System Operator Spot Demand Curve Auction Market
("Floating  Price").  For each monthly  settlement  period, the price difference
will equal the Fixed Price minus the Floating Price. If such price difference is
less than zero,  Morgan  Stanley will pay KeySpan an amount equal to the product
of (a)  the  Notional  Quantity  and  (b)  the  absolute  value  of  such  price
difference.  Conversely,  if such price difference is greater than zero, KeySpan
will pay Morgan  Stanley  an amount  equal to the  product  of (a) the  Notional
Quantity and (b) the absolute value of such price  difference.  KeySpan believes
that the average  annual  monthly  capacity  market  price will settle above the
Fixed Price.

The New York  State  competitive  wholesale  market  for  capacity,  energy  and
ancillary  services  administered  by the NYISO is still  evolving  and 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 2005 summer capacity of all of our steam
generation facilities and gas turbine ("GT") units as reported to the NYISO:

--------------------------------------------------------------------------------
Location of Units           Description                        Units      MW
                                                  Fuel
--------------------------------------------------------------------------------
Long Island City            Steam Turbine         Dual*        3          1737
Long Island City            Combined Cycle        Dual*        1          226
Northport, L.I.             Steam Turbine         Dual*        4          1550
Port Jefferson, L.I.        Steam Turbine         Dual*        2          388
Glenwood, L.I.              Steam Turbine         Gas          2          240
Island Park, L.I.           Steam Turbine         Dual*        2          396
Far Rockaway, L.I.          Steam Turbine         Dual*        1          110
Long Island City            GT Units              Dual*        17         438
Glenwood and Port           GT Units              Dual         4          154
Jefferson Energy Center,
L.I.
Throughout L.I.             GT Units              Dual*        12         301
Throughout L.I.             GT Units              Oil          30         1060
                                                               --         ----

TOTAL                                                          78         6600

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


For additional information and for financial 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"
and Note 2 to the Consolidated Financial Statements, "Business Segments".

Agreements with LIPA

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,  KeySpan and LIPA entered into three
major long-term service  agreements,  the 1998 MSA, 1998 PSA and 1998 EMA. Under
these  agreements,  as well as through  additional  power  purchase  agreements,
KeySpan  provides:  4,214 MW of power generation  capacity and energy conversion
services;  operation,  maintenance and capital  improvement  services for LIPA's
transmission and distribution system; and energy management services.

On February  1, 2006,  KeySpan and LIPA  entered  into the 2006 LIPA  Agreements
which will  become  effective  as of January 1, 2006,  following  receipt of all
necessary governmental  approvals,  which are pending. The effectiveness of each
of the 2006 LIPA Agreements is conditioned  upon all of the 2006 LIPA Agreements
becoming effective.

2006  Settlement  Agreement.  Pursuant  to  the  terms  of the  2006  Settlement
Agreement,  KeySpan and LIPA agreed to resolve issues that have existed  between
the  parties  relating  to the  various  agreements  effective  in May 1998.  In
addition to the  resolution of these matters,  KeySpan's  entitlement to utilize
LILCO's  available  tax  credits and other tax  attributes  will  increase  from
approximately  $50 million to  approximately  $200  million.  These  credits and


                                       11
<PAGE>


attributes  may be used  to  satisfy  KeySpan's  previously  incurred  indemnity
obligation to LIPA for any federal income tax liability that may result from the
settlement of a pending  Internal  Revenue Service ("IRS") audit for LILCO's tax
year ended March 31, 1999.  In  recognition  of these items,  as well as for the
modification and extension of the 1998 MSA and the elimination of the GPRA, upon
effectiveness of the 2006 Settlement Agreement KeySpan will record a contractual
asset in the amount of approximately $160 million,  of which  approximately $110
million will be attributed to the right to utilize such  additional  tax credits
and  attributes and  approximately  $50 million will be amortized over the eight
year  term of the  2006  MSA.  In order to  compensate  LIPA for the  foregoing,
KeySpan  will pay LIPA $69  million  in cash and will  settle  certain  accounts
receivable in the amount of approximately $90 million due from LIPA.

Generation Purchase Rights Agreement and 2006 Option Agreement. Under an amended
GPRA,  LIPA had the right 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.
LIPA was initially  required to exercise its option by May 2005, but KeySpan and
LIPA agreed to extend the date by which LIPA was to make this  determination  to
December 15, 2005.  Pursuant to the December 2005 settlement between KeySpan and
LIPA, the parties entered into the 2006 Option  Agreement,  whereby LIPA has the
option  during the period  January 1, 2006 to December 31, 2006 to purchase only
KeySpan's  Far Rockaway  and/or E.F.  Barrett  Generating  Stations (and certain
related  assets) at a price  equal to the net book value of each  facility.  The
2006 Option Agreement replaces the GPRA, the expiration of which has been stayed
pending effectiveness of the 2006 LIPA Agreements which are pending governmental
approvals.  In the event such  agreements  do not become  effective by reason of
failure to secure requisite governmental approvals,  the GPRA will be reinstated
for a period of 90 days. If LIPA were to exercise the option and purchase one or
both of the  generation  facilities  (i) LIPA and  KeySpan  will  enter  into an
operation and maintenance agreement,  pursuant to which KeySpan will continue to
operate these  facilities  through May 28, 2013 for a fixed  management fee plus
reimbursement  for  certain  costs;  and (ii) the 1998 PSA and 1998 EMA would be
amended to reflect that the purchased  generating  facilities would no longer be
covered by those  agreements.  It is anticipated that the fees received pursuant
to the  operation  and  maintenance  agreement  will offset the reduction in the
operation and  maintenance  expense  recovery  component of the 1998 PSA and the
reduction in fees under the 1998 EMA.

It is also contemplated that to the extent any emission credits  attributable to
the acquired facilities are not needed to satisfy the operating  requirements of
such plants,  such excess emissions  credits will be pooled and applied pro rata
to satisfy the operating requirements of KeySpan's generating facilities subject
to the amended  PSA.  Thereafter,  any  remaining  credits  attributable  to the
acquired plants may be sold by LIPA, who shall retain 100% of the net proceeds.

Management Services  Agreement.  Pursuant to the 1998 MSA, we perform day-to-day
operation  and  maintenance   services  and  capital   improvements  for  LIPA's
transmission  and  distribution  system,   including,   among  other  functions,
transmission and distribution facility operations, customer service, billing and
collection,  meter reading,  planning,  engineering,  and  construction,  all in
accordance with policies and procedures  adopted by LIPA. KeySpan furnishes such
services  as an  independent  contractor  and does not  have  any  ownership  or
leasehold interest in the transmission and distribution system.


                                       12
<PAGE>


In exchange for providing  these  services,  we are  reimbursed for our budgeted
costs and entitled to earn an annual  management fee of $10 million and may also
earn certain  cost-based  incentives,  or be responsible for certain  cost-based
penalties. The incentives provided us the ability 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 accrued to LIPA. The penalties
required  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,  the agreement
provided  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 apply, for system reliability, worker
safety, and customer  satisfaction.  In 2005, we earned $7.4 million in non-cost
performance incentives.

The 1998 MSA was  originally  set to expire on May 28, 2006,  but in 2005 it was
extended  through  December 31, 2008,  in  connection  with the extension of the
option  period under the GPRA as was more fully  described in the  discussion on
"Generation Purchase Rights Agreement and 2006 Option Agreement" above.

As a result of the recent  negotiations and settlement  between KeySpan and LIPA
discussed  above,  the  parties  entered  into a 2006  MSA.  Under the 2006 MSA,
KeySpan  will  continue  to perform the  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, meter reading,  planning,
engineering,  and construction,  all in accordance with prudent utility practice
and  policies  and  procedures  adopted  by LIPA.  The 2006 MSA will not  become
effective unless and until all governmental  approvals are received and, only if
all of the 2006 LIPA Agreements are approved. If all governmental  approvals are
received,  then  the  2006 MSA will be  implemented  with an  effective  date of
January 1, 2006 and will operate through December 31, 2013.

In place of the previous compensation  structure (whereby KeySpan was reimbursed
for budgeted  costs,  and earned a management  fee and certain  performance  and
cost-based incentives), KeySpan's compensation for managing the T&D System under
the 2006 MSA consists of two  components:  a minimum  compensation  component of
$224 million per year and a variable component based on electric sales. The $224
million  component  will  remain  unchanged  for three  years and then  increase
annually by 1.7%, plus inflation. The variable component, which will comprise no
more than 20% of  KeySpan's  compensation,  is based on  electric  sales on Long
Island  exceeding a base amount of 16,558 gigawatt hours,  increasing by 1.7% in
each year. Above that level,  KeySpan will receive  approximately 1.34 cents per
kilowatt hour for the first contract  year,  1.29 cents per kilowatt hour in the
second  contract  year  (plus an annual  inflation  adjustment),  1.24 cents per
kilowatt hour in the third contract year (plus an annual inflation  adjustment),
with the per  kilowatt  hour rate  thereafter  adjusted  annually by  inflation.
Subject to certain  limitations,  KeySpan will be able to retain all operational
efficiencies realized during the term of the 2006 MSA.

LIPA will  continue to reimburse  KeySpan for certain  expenditures  incurred in
connection  with the  operation  and  maintenance  of the T&D System,  and other
payments made on behalf of LIPA,  including:  real property and other T&D System
taxes, return postage, capital construction expenditures and storm costs.


                                       13
<PAGE>


The 2006 MSA  provides for a number of  performance  metrics  measuring  various
aspects of KeySpan's  performance in the operations and customer  service areas.
Poor  performance  in any metric may  subject  KeySpan  to  financial  and other
non-cost  penalties  (such  financial  penalties not to exceed $7 million in the
aggregate for all performance metrics in any contract year).  Subject to certain
limitations,  superior  performance  in  certain  metrics  can be used to offset
underperformance  in  other  metrics.   Consistent  failure  to  meet  threshold
performance levels for two metrics,  System Average Interruption  Duration Index
(two out of three  consecutive  years) and  Customer  Satisfaction  Index (three
consecutive years), will constitute an event of default under the 2006 MSA.

Should LIPA sell the T&D System to a private  entity during the term of the 2006
MSA,  LIPA shall have the right to terminate  the 2006 MSA,  provided  that LIPA
will be required to pay KeySpan's reasonable  transition costs and a termination
fee of (a) $28 million if the termination  date occurs on or before December 31,
2009,  and (b) $20 million if the  termination  date occurs  after  December 31,
2009.

Power Supply Agreement.  A KeySpan  subsidiary sells to LIPA all of the capacity
and,  to  the  extent  requested,  energy  conversion  services  from  our  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.  Since  October  1,  2004,  pursuant  to a FERC  approved
settlement,  the rates reflect a cost of equity of 9.5% with no revenue increase
in the  first  year of the new rate  period.  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 ("MWh") dispatched. LIPA has no
obligation  to  purchase  energy  conversion  services  from  us and is  able to
purchase  energy or energy  conversion  services on a least-cost  basis from all
available sources  consistent with existing  interconnection  limitations of the
T&D system. The PSA provides  incentives and penalties that can total $4 million
annually for the maintenance of the output  capability and the efficiency of the
generating  facilities.  In 2005, we earned $4 million in  incentives  under the
PSA.

The 1998 PSA runs for an original term of 15 years,  expiring in 2013.  The 1998
PSA has a renewal  provision  for an  additional  15 years on  similar  terms at
LIPA's  option.  However,  the 1998 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 1998 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 1998 PSA.
If LIPA  ramps-down the  generation  capacity in years 11 through 15 of the 1998
PSA,  the  capacity  charges  otherwise  payable  by  LIPA  will be  reduced  in
accordance  with a formula  established  in the 1998 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 1998 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 1998 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 GPRA discussed in greater detail above


                                       14
<PAGE>


Energy Management Agreement.  Pursuant to the 1998 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 2005,  the EMA was  amended to extend  the term for the  services
described in (ii) and (iii) through December 31, 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 2005, we earned EMA
incentives in an aggregate of $5 million.

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 1998 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  ("NYSDEC"),  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.

In March  2005,  LIPA issued a Request for  Proposal  ("RFP") to provide  system
power supply  management  services  beginning  May 29, 2006 and fuel  management
services for certain of its peaking  generating units beginning January 1, 2006.
A KeySpan subsidiary is currently performing these services. KeySpan submitted a
bid in  response to the new RFP in April 2005.  LIPA was  scheduled  to select a
service  provider in June 2005,  but has deferred such decision at this time. We
cannot predict the outcome or the timing of any decisions by LIPA on this matter
at this time.  Pending  LIPA's  determination  on the RFP,  the EMA was extended
through December 31, 2006.

Power  Purchase  Agreements  with KeySpan  Glenwood and KeySpan Port  Jefferson.
KeySpan Glenwood Energy Center, LLC and KeySpan Port Jefferson Energy Center LLC
each have 25 year power  purchase  agreements  with LIPA  expiring  in 2027 (the
"2002 LIPA  PPAs").  Under the terms of the 2002 LIPA PPAs,  these  subsidiaries
sell capacity,  energy conversion  services and ancillary services to LIPA. Each
plant is designed to produce 79.9 MW.  Pursuant to the 2002 LIPA 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. In 2005, LIPA completed the strategic organizational review
initiative it commenced in 2004. As part of its strategic review, LIPA engaged a
team of  advisors  and  consultants,  held  public  hearings  and  explored  its
strategic options, including continuing its existing operations, municipalizing,


                                       15
<PAGE>


privatizing,  selling some,  but not all of its assets,  becoming a regulator of
rates and services, or merging with one or more utilities.  The strategic review
team also  considered  whether  LIPA should  exercise its option under the GPRA.
Upon completion of its strategic review,  LIPA determined that it would continue
its existing organizational structure and engage KeySpan in the renegotiation of
the 1998 MSA, GPRA and related  agreements.  As stated above, these negotiations
culminated in the parties entering into the 2006 LIPA Agreements.  As previously
noted,  the  2006  LIPA  Agreements  are  subject  to  receipt  of  governmental
approvals.  Also,  the LIPA  Agreements do not preclude LIPA from  continuing to
explore privatization, municipalization or other strategic alternatives.

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 (from May 1998) 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 (from May 1998), 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 (from May 1998) 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
1998 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.


                                       16
<PAGE>


ENERGY SERVICES OVERVIEW

The Energy  Services  segment  includes  companies  that provide  energy-related
services to customers located  primarily within the Northeastern  United States,
with  concentrations  in the  New  York  City  and  Boston  metropolitan  areas.
Subsidiaries in this segment provide residential and small commercial  customers
with  service  and  maintenance  of energy  systems and  appliances,  as well as
operation  and  maintenance,  design,  engineering,  consulting  and fiber optic
services to commercial, institutional and industrial customers. Our subsidiaries
in this  segment have over  200,000  service  contracts in place to provide home
energy services,  completed over 250,000 service calls during 2005 and completed
more than 16,000 installations during 2005.

In  January  and  February  of 2005,  KeySpan  sold its  mechanical  contracting
subsidiaries in this segment and exited such businesses. These subsidiaries were
engaged in design, building,  installing and servicing heating,  ventilation and
air  conditioning  ("HVAC")  systems and  plumbing  systems for  industrial  and
commercial customers. In the fourth quarter of 2004, KeySpan's investment in its
discontinued   mechanical  contracting   subsidiaries  was  written-down  to  an
estimated fair value. 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.

For  additional  information  and financial  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",
Item  8.  "Financial   Statements  and  Supplementary   Data",  Note  2  to  the
Consolidated  Financial  Statements,  "Business  Segments"  and Note 10  "Energy
Services - "Discontinued Operations".

ENERGY INVESTMENTS OVERVIEW

We are also engaged in Energy  Investments  which includes gas  exploration  and
production  activities,  domestic  pipelines,  gas  storage  facilities  and LNG
facilities and operations.

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 KeySpan, to
explore  for  and  produce  natural  gas  and  oil.   KeySpan   Exploration  and
Production's  remaining  venture  assets are primarily  proved  undeveloped  oil
reserves  located  off the Gulf of  Mexico in the South  Timbalier  and  Mustang
Island areas.

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.


                                       17
<PAGE>


Domestic Pipelines and Gas Storage Facilities

We own a 20.4% interest in Iroquois Gas Transmission System LP, a partnership of
affiliates of six U.S. and Canadian  energy  companies,  which is the owner of a
411-mile interstate natural gas pipeline extending from the U.S.-Canadian border
at Waddington,  NY through western  Connecticut to its terminus in Commack,  NY,
and from  Huntington  to the Bronx.  Its wholly owned  subsidiary,  the Iroquois
Pipeline Operating Company,  headquartered in Shelton, Connecticut, is the agent
for and  operator of the  pipeline.  The Iroquois  pipeline can  transport up to
1,124,500 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 304,950 DTH of gas per day.

We also have a 50% interest in Islander East Pipeline  Company,  LLC  ("Islander
East"),  which 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. In addition, we own a 21% ownership interest in the
Millennium  Pipeline project which is anticipated to transport up to 525,000 DTH
of natural gas a day from Corning to Ramapo, New York,  interconnecting with the
pipeline systems of various other utilities in New York.

We are also the owner and operator of a 600,000 barrel LNG storage and receiving
facility located in Providence,  Rhode Island, known as KeySpan LNG. We acquired
the KeySpan LNG facility  from  Algonquin  LNG, a  subsidiary  of Duke Energy on
December 12, 2002. Our subsidiary, Boston Gas is the facility's largest customer
and contracts for more than half of the LNG facility's  storage.  KeySpan LNG is
regulated by FERC.

For  additional  information  concerning  these energy  related  investments  in
pipelines and gas storage facilities, see the discussion on "Energy Investments"
in Item 7  Management's  Discussion  and  Analysis of  Financial  Condition  and
Results of Operations contained herein.

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 4.3  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.


                                       18
<PAGE>


Former Energy Investments

KeySpan had previously  been involved in natural gas  distribution  and pipeline
activities in the United Kingdom.  However,  on March 18, 2005, KeySpan sold its
50% interest in Premier Transmission  Limited  ("Premier"),  a gas pipeline from
southwest  Scotland to Northern  Ireland pursuant to an agreement among KeySpan,
its 50% partner, BG Energy Holdings Limited and Premier  Transmission  Financing
Public  Limited  Company  ("PTFPL"),  pursuant  to which all of the  outstanding
shares of PTL were purchased by PTFPL. In two transactions in April and December
2004, KeySpan sold its ownership in KeySpan Energy Canada Partnership  ("KeySpan
Canada") a company that owned  certain  midstream  natural gas assets in Western
Canada.

For  additional  information  and financial  information  concerning  the Energy
Investments  segment,  see the discussion in Item 7 Management's  Discussion and
Analysis of Financial Condition and Results of Operations - "Energy Investments"
and Note 2 to the Consolidated Financial Statements, "Business Segments".

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.

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 were submitted in a timely
manner for 13 existing  facilities whose initial permits were to expire in 2004.
To date,  all of the permits  except one were renewed and the remaining  renewal
application has been deemed complete by NYSDEC and is undergoing final review by
the United States Environmental Protection Agency ("EPA"). During 2005, a timely
renewal  application  was submitted for a facility whose permit expires in 2006.
The permits and timely renewal applications allow our electric generating plants
to continue to operate without any additional significant  expenditures,  except
as described below.


                                       19
<PAGE>


Our generating  facilities are located within a CAA ozone  non-attainment and PM
2.5 (fine particulate matter)  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  and forthcoming  requirements
under the Clean Air Interstate Rule ("CAIR")  designed to address both ozone and
particulate  matter.  Our  previous  investments  in low NOX  boiler  combustion
modifications,  the use of  natural  gas firing  systems  at our steam  electric
generating stations,  and the compliance  flexibility  available under these cap
and trade  programs,  have enabled  KeySpan to achieve the  emission  reductions
required  in a  cost-effective  manner.  KeySpan is  developing  its  compliance
strategy in response to the  implementation  of CAIR, which is expected in 2009.
Since detailed  requirements under CAIR have not yet been fully articulated,  it
is not  possible  to  definitively  estimate  capital  expenditures  that may be
required to meet these regulatory mandates.  Although it is anticipated that NOx
control  equipment  may be  required  at one or more of  KeySpan's  Long  Island
facilities  at a cost of between $25 to $35 million.  However,  such amounts are
recoverable from LIPA pursuant to the 1998 PSA, or if applicable, the 2006 PSA.

In 2003, New York State promulgated regulations which establish separate NOX and
SO2 emission  reduction  requirements on electric  generating  facilities in New
York State,  which  commenced in late 2004 for NOX emissions and in 2005 for SO2
emissions.   KeySpan's  facilities  have  been  able  to  comply  with  the  NOX
requirements   without  material  additional  capital  expenditures  because  of
previously installed emissions control equipment and gas combustion  capability.
SO2  compliance  was achieved  through a reduction in the sulfur  content of the
fuel oil used in our  Northport  and Port  Jefferson  facilities  and a  further
reduction is expected to be required in 2008.

In 2004,  the EPA issued  regulations  that  require  reductions,  on a national
basis, of mercury  emissions from electric  generating  facilities on a national
basis. The mercury  regulations have no impact on KeySpan facilities since their
application  is  limited  to  coal-fired  plants.  EPA  determined  that  nickel
emissions  from  oil  fired  plants  do  not  pose  health  risks  that  require
regulation.  This  determination  has been challenged and litigation is pending.
Until a final outcome is obtained, the nature and extent of the financial impact
on KeySpan from nickel regulation, if any, cannot be determined.

In 2003, the Governor of New York initiated a Regional Greenhouse Gas Initiative
that seeks to establish a coordinated  multi-state plan to reduce greenhouse gas
emissions  (primarily carbon dioxide ("CO2")) from electric  generating emission
sources in the Northeast. In December of 2005, seven northeast states, including
New York,  issued a  memorandum  of  understanding  capping CO2  emissions  from
electric  generating  facilities  in 2009  and,  beginning  in  2015,  gradually
requiring a 10 percent  reduction  in regional  emissions  by 2018.  Each of the
seven states will be promulgating  individual  state rules to implement the MOU.
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  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 the  Ravenswood  Generating  Station in 2004 has  further  reduced
average KeySpan CO2 emission rates.


                                       20
<PAGE>


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 NYSDEC.  We are  currently  conducting  studies as directed by the NYSDEC to
determine the impacts of our discharges on aquatic  resources and are engaged in
discussions  with the NYSDEC  regarding the nature of capital  upgrades or other
mitigation measures necessary to satisfy these evolving regulatory requirements.
It is  difficult  to  predict  with any  certainty  the  costs  of such  capital
investments, but these upgrades are expected to cost up to $60 million. However,
such amounts are recoverable  from LIPA pursuant to the 1998 PSA, or applicable,
the 2006 PSA. The Ravenswood  Generating  Station may also require upgrades at a
cost of up to $15 million.  The actual expenditures will depend upon the outcome
of the ongoing studies and the subsequent  determination by the NYSDEC of how 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  investigating  and
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.  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  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.


                                       21
<PAGE>


The Ravenswood  Generating Station,  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.

Regulation. Public utility holding companies, like KeySpan, are now regulated by
the FERC pursuant to PUHCA 2005 and to some extent by state utility  commissions
through the regulation of certain affiliate transaction regulations. Our utility
subsidiaries  are subject to extensive  federal and state regulation by FERC and
state utility  commissions.  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 MADTE 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  also  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.  As noted above,  our  regulated  gas  distribution
utility  subsidiaries  are subject to regulation by the NYPSC,  MADTE and NHPUC.
The NYPSC  regulates KEDNY and KEDLI.  Although  KeySpan 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  Station under a
lightened  regulatory  standard.  Our KEDNE  subsidiaries and to some extent our
service companies are also subject to regulation by the MADTE and NHPUC.

Securities and Exchange  Commission.  As a result of the  acquisition of Eastern
and  EnergyNorth,  we became a holding  company under PUHCA 1935. The Energy Act
repealed PUHCA 1935 and replaced it with PUHCA 2005 effective  February 8, 2006.
Whereas our corporate and financial activities and those of our subsidiaries had
been subject to regulation by the SEC, FERC now has jurisdiction over certain of
our holding company activities.  However, the SEC continues to have jurisdiction
over  the  registration  and  issuance  of  our  securities  under  the  federal
securities laws.

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


                                       22
<PAGE>


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.

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 1935,  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.  The  regulation of our three service  companies has also
been transferred to FERC under PUHCA 2005.

Federal Energy Regulatory Commission.  FERC has jurisdiction over certain of our
holding company activities,  including (i) regulating certain transactions among
our affiliates  within our holding company system;  (ii) governing the issuance,
acquisition  and  disposition  of securities and assets by certain of our public
utility   subsidiaries;   and  (iii)  approving   certain  utility  mergers  and
acquisitions. In addition to its new authority pursuant to PUHCA 2005, FERC also
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 Generating Station are subject to FERC
regulation based on their wholesale energy transactions.

Our  Ravenswood  Generating  Station's  rates are based on a  market-based  rate
application  approved by FERC. The rates that our Ravenswood  Generating Station
may charge are subject to FERC mandated  mitigation measures due to market power
issues. 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 Generating Station'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 Generating Station 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.


                                       23
<PAGE>


Executive Officers of KeySpan

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

Robert B. Catell

Mr.  Catell,  age 69, 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
(NYSE:THX),   Independence   Community  Bank  (NASDAQ:ICBC)  and  Keyera  Energy
Management Ltd. (TSX:KEY.UN)

Robert J. Fani

Mr.  Fani,  age 52, 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.

Wallace P. Parker Jr.

Mr. Parker,  age 56, 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 56, 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


                                       24
<PAGE>


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 KeySpan,  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 56, 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
KeySpan'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.

John A. Caroselli

Mr.  Caroselli,  age 51, 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,   Customer
Relations and Information Technology Strategy and Governance. 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 62, 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.  (NYSE:IKN)
and Technology Solutions Company (NASDAQ:TSCC).

David J. Manning

Mr. Manning,  age 55, 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 Queen's Counsel.


                                       25
<PAGE>


Anthony Nozzolillo

Mr.  Nozzolillo,  age 57, was  elected  Executive  Vice  President  of  Electric
Operations in February  2000. He previously  served as Senior Vice  President of
KeySpan's  Electric  Business Unit from December 1998 to January 2000. He joined
LILCO  in 1972  and held  various  positions,  including  Manager  of  Financial
Planning  and  Manager of Systems  Planning.  Mr.  Nozzolillo  served as LILCO's
Treasurer  from 1992 to 1994 and as Senior Vice  President  of Finance and Chief
Financial Officer from 1994 to 1998.

Lenore F. Puleo

Ms. Puleo,  age 52, 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 47, 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  (NASDAQ:EBTC)  and  Dynamics  Research
Corporation (NASDAQ:DRCO).

Joseph F. Bodanza

Mr. Bodanza,  age 58, 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 47, 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.


                                       26
<PAGE>


John F. Haran

Mr. Haran,  age 55, 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 50, 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 59, 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,  age 46, 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 44, 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.


                                       27
<PAGE>


Joseph E. Hajjar

Mr. Hajjar,  age 53, 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 49, 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.

EMPLOYEE MATTERS

As  of  December  31,  2005,  KeySpan  and  its  wholly-owned  subsidiaries  had
approximately 9,700 employees. Of that total,  approximately 6,154 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.

ITEM 1A. RISK FACTORS

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 the following:

We are a Holding  Company,  and Our Subsidiaries are Subject to State Regulation
Which Limits Their Ability to Pay Dividends and Make Distributions to Us

     We are a holding  company 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.


                                       28
<PAGE>


     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, 2005 and November 30, 2005, 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.

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

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

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

     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 capacity,  energy and ancillary services
     from  our  Ravenswood   Generating  Station  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
     capacity,  energy  sales and  ancillary  services in to the NYISO market is
     still  evolving.  and some of the  FERC's  price  mitigation  measures  are
     subject to rehearing and possible  judicial review,  as well as revision in
     response to market participant complaints or NYISO requests.


                                       29
<PAGE>


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

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

     In  addition,  our  business  is  subject  to many  hazards  from which our
     insurance may not adequately provide coverage.  An unexpected outage at our
     Ravenswood Generating Station, especially in the significant summer period,
     could  materially  impact  our  financial  results.  Damage  to  pipelines,
     equipment,  properties and people caused by natural  disasters,  accidents,
     terrorism  or other  damage by third  parties  could  exceed our  insurance
     coverage.  Although we do have  insurance to protect  against many of these
     contingent  liabilities,  this insurance is capped at certain  levels,  has
     self-insured retentions and does not provide coverage for all liabilities.

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

     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  Station  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.


                                       30
<PAGE>


A Substantial  Portion Of Our Revenues Are Derived From Our Agreements With LIPA
And No Assurances Can Be Made That These  Arrangements  Will Not Be Discontinued
At Some Point In The Future Or That The New Agreements Will Become Effective.

     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. On February 1, 2006, KeySpan and LIPA
     entered into amended and restated  agreements whereby KeySpan will continue
     to operate  and  maintain  the  electric  T&D System  owned by LIPA on Long
     Island. As part of the amended agreements, the GPRA, pursuant to which LIPA
     had the option,  through December 15, 2005, to acquire substantially all of
     the  electric  generating  facilities  owned by KeySpan  on Long  Island is
     replaced  with the 2006 Option  Agreement  where LIPA only has the right to
     acquire  two of our  facilities,  our  Far  Rockaway  and/or  E.F.  Barrett
     Generating Stations during the period January 1, 2006 to December 31, 2006.
     Additionally,  the new agreements  resolve many outstanding  issues between
     the parties  regarding the current LIPA  Agreements and provide new pricing
     and  extensions of the  Agreements.  There is a risk that these  agreements
     will not receive the necessary governmental  approvals,  which are pending,
     and the  effectiveness  of each of the 2006 LIPA  Agreements is conditioned
     upon all of the 2006 LIPA Agreements becoming  effective.  If the 2006 LIPA
     Agreements do not become effective, there is uncertainty as to whether LIPA
     will exercise  their option under the GPRA and the status of the resolution
     of the various disputes between KeySpan and LIPA.

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 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


                                       31
<PAGE>


     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, financial condition
     and cash flows.

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  capacity,  energy and ancillary
     services  they sell. In addition,  if new  generation  and/or  transmission
     facilities  are  constructed,  and/or the  availability  of our  Ravenswood
     Generating Station deteriorates, then the quantities of capacity and energy
     sales  could be  adversely  affected.  In  December  2005,  NYPA  completed
     construction of a nominal 500 MW generating  facility in New York City, and
     it began  selling  its  capacity  and  energy  into the NYISO  markets.  In
     addition,  another  nominal 500 MW facility is expected to come  on-line in
     2006.  We  cannot  predict,  however,  when  or  if  new  power  plants  or
     transmission  facilities in addition to the  above-noted  resources will be
     built or the  nature  of the  future  New York  City  capacity  and  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.

Risk Associated with our Financial Swap Agreement for In-City Unforced Capacity

     KeySpan believes that the New York City market represents a strong capacity
     market due to,  among other  things,  its local  reliability  rules  (which
     recently  increased  to 83%  from  80%),  increasing  demand  and the  time
     required for new  resources to be  constructed.  KeySpan  anticipates  that
     demand will  increase and that the high cost to  construct  capacity in New
     York City will  result  in  favorable  In-City  Unforced  Capacity  prices.
     Therefore,  KeySpan  entered into an ISDA Master  Agreement for a fixed for
     floating  unforced  capacity  financial  swap for a  notional  quantity  of


                                       32
<PAGE>


     1,800,000kW  at the Fixed  Price is  $7.57/kW-month.  If the demand is less
     than KeySpan's  estimates,  additional resources enter the market, or costs
     are less  than  forecast,  In-City  Unforced  Capacity  prices  could be on
     average  less than the Fixed Price  resulting  in a loss to KeySpan,  which
     under certain circumstances could be material.

Labor  Disruptions  at Our  Facilities  Could  Adversely  Affect Our  Results of
Operations and Cash Flow

     Approximately 6,154 employees, or 63% of our employees,  are represented by
     unions through various collective bargaining agreements that expire between
     2006  and  2009.  The  bargaining   agreements   expiring  in  2006  affect
     approximately  1,300  employees  who  primarily  work for  KEDNE and at our
     Ravenswood Generating Station. KeySpan is currently engaging in discussions
     with these unions for new collective bargaining agreements.  It is possible
     that our  employees  may seek an  increase  in wages  and  benefits  at the
     expiration of these agreements,  and that we may be unable to negotiate new
     agreements without labor disruption.

Counterparties to Our Transactions May Fail to Perform their Obligations,  Which
Could Harm Our Results of Operations

     Our  operations  are  exposed  to  the  risk  that  counterparties  to  our
     transactions  that  owe  us  money  or  supplies  will  not  perform  their
     obligations.  Should the  counterparties  to  arrangements  with us fail to
     perform, we might be forced to enter into alternative hedging  arrangements
     or honor our underlying  commitment at then-current  market prices that may
     exceed our contractual  prices.  In such event,  we might incur  additional
     losses to the extent of amounts,  if any,  already paid to  counterparties.
     This risk is most significant  where we have  concentrations of receivables
     from natural gas and electric  utilities and their  affiliates,  as well as
     industrial  customers  and marketers  throughout  the  Northeastern  United
     States.

We Are Exposed to Risks That Are Beyond Our Control

     The cost of repairing damage to our operating subsidiaries'  facilities and
     the potential  disruption of their operations or supplier operations due to
     storms,  natural  disasters,  wars,  terrorist acts and other  catastrophic
     events could be substantial. The occurrence or risk of occurrence of future
     terrorist  attacks or related acts of war may lead to increased  political,
     economic and  financial  market  instability  and  volatility in prices for
     natural gas which could  materially  adversely  affect us in ways we cannot
     predict at this time. A lower level of economic activity for these or other
     reasons  could  result in a  decline  in energy  consumption,  which  could
     adversely affect our net revenues.

The Long-Term  Financial  Condition of Our Gas Distribution  Business Depends on
the Continued Availability of Natural Gas Reserves

     The  development of additional  natural gas reserves  requires  significant
     capital  expenditures  by others for  exploring,  drilling  and  installing
     production,  gathering,  storage,  transportation and other facilities that
     permit  natural  gas to be  produced  and  delivered  to  our  distribution
     systems. Low prices for natural gas, regulatory  restrictions,  or the lack
     of  available  capital  for  these  projects  could  adversely  affect  the


                                       33
<PAGE>


     development  of  additional  natural gas reserves.  Additional  natural gas
     reserves may not be developed in sufficient  amounts to fill the capacities
     of our  distribution  systems,  thus  limiting our  prospects for long-term
     growth.

Gathering,  Processing and Transporting  Activities  Involve Numerous Risks that
May Result in Accidents and Other Operating Risks and Costs

     Our gas  distribution  facilities  pose a variety of hazards and  operating
     risks, such as leaks,  explosions and mechanical problems caused by natural
     disasters,  accidents,  terrorism or other damage by third  parties,  which
     could cause  substantial  financial  losses.  In addition to impairing  our
     operations,  these  risks  could  also  result  in loss of  human  life and
     environmental  pollution. In accordance with standard industry practice, we
     maintain  insurance against some, but not all, of these potential risks and
     losses.  The  occurrence  of any of  these  events  not  fully  covered  by
     insurance could have a material  adverse effect on our financial  position,
     results of operations and cash flows.

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

     -    volatility of fuel prices used to generate electricity;

     -    fluctuations in weather and in gas and electric prices;

     -    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;

     -    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;

     -    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;

     -    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 NYISO,  our two largest
          customers; and

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


                                       34
<PAGE>


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.


ITEM 1B     UNRESOLVED STAFF COMMENTS.

None.

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, 2005.


                                       35
<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, 2006,
there were  approximately  68,318  registered record holders of KeySpan's common
stock.  In the fourth  quarter of 2005,  KeySpan  increased  its  dividend to an
annual rate of $1.86 per common share  beginning with the quarterly  dividend to
be paid in February  2006.  Our dividend  framework 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 $1.86 level to be paid on a quarterly basis at a rate of $0.465.
KeySpan's  scheduled  dividend payment dates are February 1, May 1, August 1 and
November 1, or the next business day, if such date is not a business day.

The following  table sets forth,  for the quarters  indicated,  the high and low
sales prices and dividends declared per share for the periods indicated:

  2005                       High             Low           Dividends Per Share
  -----------------------------------------------------------------------------
  First Quarter              $40.90           $38.04        $0.455
  Second Quarter             $40.88           $36.83        $0.455
  Third Quarter              $41.03           $36.35        $0.455
  Fourth Quarter             $37.10           $32.66        $0.455

  2004                       High             Low           Dividends Per Share
  -----------------------------------------------------------------------------
  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







                                       36


<PAGE>




                      EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth  securities  authorized for issuance under equity
compensation plans for the year ended December 31, 2005:

<TABLE>
<CAPTION>

                                                                                                   Number of securities remaining
                                         Number of securities                                       available for future issuance
                                      to be issued upon exercise     Weighted-average exercise     under equity compensation plans
                                       of outstanding options,         price of outstanding        (excluding securities reflected
              Plan category              warrants and rights       options, warrants and rights            in column (a))
              -------------              -------------------       ----------------------------    -------------------------------
                                                 (a)                            (b)                              (c)
<S>                                    <C>                                     <C>                      <C>
Equity compensation plans
approved by security holders

KeySpan Long Term
Incentive Compensation Plan

       Stock Options                        10,443,055                         $33.74                              -

       Restricted Stock                         90,599                            N/A                              -

       Performance Shares                     555,927                             N/A                              -

Equity compensation plans not
approved by security holders                     N/A                              N/A                             N/A

Total                                   11,089,581(1)                          $33.74                     3,736,121(2)
</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.

(2)  This  total  amount  reflects  the  aggregate   number  of  stock  options,
     restricted stock and performance  shares available for issuance pursuant to
     KeySpan's Long Term Incentive Compensation Plan.


                                       37

<PAGE>

<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA

--------------------------------------------------------------------------------------------------------------------
                                                                       Year Ended December 31,
(In Millions of Dollars, Except Per Share
Amounts)                                              2005         2004         2003         2002         2001
--------------------------------------------------------------------------------------------------------------------
Income Summary
<S>                                               <C>          <C>          <C>          <C>         <C>
Revenues
     Gas Distribution                            $ 5,390.1    $ 4,407.3    $ 4,161.3    $ 3,163.8   $ 3,613.6
     Electric Services                             2,042.8      1,738.7      1,606.0      1,645.7     1,850.4
     Energy Services                                 191.2        182.4        158.9        208.6       243.5
     Energy Investments                               37.9        322.1        609.3        447.1       498.3
                                                   ------------ ------------ ------------ ----------- --------------
Total revenues                                     7,662.0      6,650.5      6,535.5      5,465.2     6,205.8
                                                   ------------ ------------ ------------ ----------- --------------
Operating expenses
     Purchased gas for resale                      3,597.3      2,664.5      2,495.1      1,653.3     2,171.1
     Fuel and purchased power                        752.1        540.3        414.6        395.9       538.5
     Operations and maintenance                    1,617.9      1,567.0      1,622.6      1,631.3     1,704.4
     Depreciation, depletion and amortization        396.5        551.8        571.7        513.7       564.0
     Operating taxes                                 407.1        404.2        418.2        380.5       448.9
     Impairment Charges                                  -         41.0            -            -           -
                                                   ------------ ------------ ------------ ----------- --------------
Total operating expenses                           6,770.9      5,768.8      5,522.2      4,574.7     5,426.9
                                                   ------------ ------------ ------------ ----------- --------------
Gain on sale of property                               1.6          7.0         15.1          4.7           -
Income from equity investments                        15.1         46.5         19.2         14.1        13.1
                                                   ------------ ------------ ------------ ----------- --------------
Operating income                                     907.8        935.3      1,047.6        909.3       792.0

Other income and (deductions)                       (269.9)         4.9       (340.3)      (301.4)     (359.5)
Income taxes                                         239.3        325.5        281.3        229.6       200.5
                                                   ------------ ------------ ------------ ----------- --------------
Earnings from continuing operations                  398.6        614.7        426.0        378.3       232.0
                                                   ------------ ------------ ------------ ----------- --------------
Discontinued Operations
    Income (loss) from operations, net of tax         (4.1)       (79.0)        (1.9)        15.7        22.6
    Loss on disposal, net of tax                       2.3        (72.0)           -        (16.3)      (30.3)
                                                   ------------ ------------ ------------ ----------- --------------
Loss from discontinued operations                     (1.8)      (151.0)        (1.9)        (0.6)       (7.7)

Cumulative change in accounting principles            (6.6)           -        (37.4)           -           -
                                                   ------------ ------------ ------------ ----------- --------------
Net income                                           390.2        463.7        386.7        377.7        224.3
Preferred stock dividend requirements                  2.2          5.6          5.8          5.8          5.9
                                                   ------------ ------------ ------------ ----------- --------------
Earnings for common stock                        $   388.0     $  458.1     $  380.9     $  371.9    $   218.4
                                                   ============ ============ ============ =========== ==============
Financial Summary
Earnings per share ($)                                2.28         2.86         2.41         2.63         1.58
Cash dividends declared per share ($)                 1.82         1.78         1.78         1.78         1.78
Book value per share, year-end ($)                   25.60        24.22        22.99        20.67        20.73
Market value per share, year-end ($)                 35.69        39.45        36.80        35.24        34.65
Shareholders, year-end                              68,421       72,549       75,067       78,281       82,300
Capital expenditures ($)                             539.5        750.3      1,009.4      1,057.5      1,059.8
Total assets ($)                                  13,812.6     13,364.1     14,640.2     12,980.1     11,789.6
Common shareholders' equity ($)                    4,464.1      3,894.7      3,670.7      2,944.6      2,890.6
Preferred stock redemption required ($)                  -         75.0         75.0         75.0         75.0
Preferred stock no redemption required ($)               -            -          8.6          8.8          9.1
Long-term debt ($)                                 3,920.8      4,418.7      5,610.9      5,224.1      4,697.6
Total capitalization ($)                           8,384.9      8,333.2      9,365.2      8,252.5      7,672.3
-------------------------------------------------- ------------ ------------ ------------ ----------- --------------
</TABLE>

                                       38
<PAGE>

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

KeySpan  Corporation  (referred to in the Notes to the  Financial  Statements as
"KeySpan,"  "we,"  "us" and  "our")  is a  holding  company  that  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, lease 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 operating subsidiaries are primarily involved in gas exploration
and production;  underground gas storage;  liquefied natural gas storage; retail
electric marketing; large energy-system ownership,  installation and management;
service and  maintenance  of energy  systems;  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
"Business Segments" for additional information on each operating segment.)

Recent Developments
-------------------

On February 25, 2006,  Keyspan entered into an Agreement and Plan of Merger (the
"Merger   Agreement"),   with  National  Grid  PLC,  a  public  limited  company
incorporated  under the laws of England and Wales  ("Parent")  and National Grid
USA, Inc, a New York  Corporation  ("Merger Sub"),  pursuant to which Merger Sub
will merge with and into KeySpan (the "Merger"),  with KeySpan continuing as the
surviving  Company.  Pursuant to the Merger Agreement,  at the effective time of
the Merger,  each outstanding share of common stock, par value $.01 per share of
KeySpan (the  "Shares"),  other than shares owned by KeySpan,  shall be canceled
and  shall be  converted  into the  right to  receive  $42.00  in cash,  without
interest.

Consummation of the Merger is subject to various closing  conditions,  including
but not  limited  to the  satisfaction  or waiver of  conditions  regarding  the
receipt  of  requisite  regulatory  approvals  and the  adoption  of the  Merger
Agreement by the  stockholders  of KeySpan and the Parent.  Assuming  receipt or
waiver of the  foregoing,  it is currently  anticipated  that the Merger will be
consummated  in  early  2007.  Accordingly,   any  statements  contained  herein
concerning expectations,  beliefs, plans, objectives,  goals, strategies, future
events  or  performance   and  underlying   assumptions   are   "forward-looking
statements"  and do not take  into  account  the  occurrence  or  impact  of any
potential  strategic  transaction on the future operations,  financial condition
and cash flows of KeySpan.  However,  no assurance  can be given that the Merger
will occur, or, the timing of its completion.

At December 31, 2005,  KeySpan was a holding  company  under the Public  Utility
Holding  Company Act of 1935, as amended  ("PUHCA  1935").  In August 2005,  the
Energy  Policy Act of 2005 (the "Energy  Act") was enacted.  The Energy Act is a
broad energy bill that places an increased  emphasis on the production of energy
and promotes the development of new technologies and alternative  energy sources
and provides  tax credits to companies  that  produce  natural gas,  oil,  coal,
electricity  and  renewable  energy.  For KeySpan,  one of the more  significant
provisions of the Energy Act is the repeal of PUHCA 1935, which became effective
on February 8, 2006.  Since that time,  the  jurisdiction  of the Securities and
Exchange Commission ("SEC") over certain holding company  activities,  including
the regulation of our affiliate  transactions  and service  companies,  has been
transferred  to the  jurisdiction  of the Federal Energy  Regulatory  Commission
("FERC")  pursuant to the Public  Utility  Holding  Company Act of 2005  ("PUHCA
2005").  See  "Regulation  and Rate Matters" for  additional  information on the
Energy Act and PUHCA 2005.

                                       39
<PAGE>


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 Millions of Dollars, Except per Share Amounts)

Year Ended December 31,                                        2005                      2004                           2003
------------------------------------------------------------------------------------------------------------------------------------
                                                       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                  $ 396.4      $ 2.33         $ 609.1      $ 3.80            $ 420.2     $ 2.65
Discontinued operations                                  (1.8)      (0.01)         (151.0)      (0.94)              (1.9)     (0.01)
Cummulative change in accounting principle               (6.6)      (0.04)              -           -              (37.4)     (0.23)

------------------------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock                             $ 388.0      $ 2.28         $ 458.1      $ 2.86            $ 380.9     $ 2.41
------------------------------------------------------------------------------------------------------------------------------------

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

Core operations                                       $ 403.2      $ 2.37         $ 359.4      $ 2.25            $ 334.2     $ 2.11
Asset sales                                                 -           -           257.5        1.60                0.9          -
Non core operations                                         -           -            83.9        0.52               98.7       0.62
Impairment charges                                          -           -           (62.4)      (0.39)                 -          -
Debt redemption costs                                    (6.8)      (0.04)          (29.3)      (0.18)             (13.6)     (0.08)

------------------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations, less
           preferred stock dividends                  $ 396.4      $ 2.33         $ 609.1      $ 3.80            $ 420.2     $ 2.65
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

Earnings from Continuing Operations 2005 vs 2004

KeySpan's earnings from continuing  operations,  less preferred stock dividends,
for the year ended  December 31, 2005 were $396.4  million or $2.33 per share, a
decrease of $212.7 million,  or $1.47 per share compared to $609.1  million,  or
$3.80 per share realized in 2004. KeySpan's financial results for the year ended
December 31, 2005 and 2004,  reflect the following  items that had a significant
impact on comparative  results:  (i) earnings from core  operations;  (ii) asset
sales of non-core subsidiaries recorded in 2004 and their respective results for
2004;  (iii)  impairment  charges  recorded  in 2004;  and (iv) debt  redemption
charges recorded in both 2005 and 2004.

As  indicated  in the above  table,  KeySpan's  earnings  from  core  operations
increased $43.8 million or $0.12 per share in 2005,  primarily reflecting higher
earnings from the Electric  Services  segment,  improved results from the Energy
Services  segment,  and a  decrease  in  interest  charges.  KeySpan's  electric
services  operations  benefited  from  an  increase  in  net  electric  revenues
principally  as a result of improved  pricing due, in part,  to the warm weather
during the 2005  summer.  Lower  operating  losses  were  incurred at the Energy
Services segment as a result of lower operating expenses.

The decrease in interest  expense  resulted  from the benefits  attributable  to
lower  outstanding  debt resulting  from debt  redemptions in 2004 and the first
quarter of 2005,  as well as from the sale of Houston  Exploration  and  KeySpan
Canada.  These favorable results were somewhat offset by a decrease in operating


                                       40
<PAGE>


income  from  KeySpan's  gas  distribution  operations  as a  result  of  higher
operating  expenses,   primarily  due  to  an  increase  in  the  provision  for
uncollectible  accounts  receivable as a result of increasing  gas costs and the
adverse impact from recent collection experience.

The full benefit to earnings per share from the favorable  operating  results of
the Electric Services and Energy Services  segments,  as well as the decrease in
interest charges was offset by the higher level of common shares outstanding. On
May 16,  2005,  KeySpan  issued  12.1  million  shares of common  stock upon the
scheduled  conversion  of the MEDs Equity  Units.  The  dilutive  effect of this
issuance  on  earnings  per share for the year  ended  December  31,  2005,  was
approximately  $0.12  per  share.  (See  Note  6 to the  Consolidated  Financial
Statements  "Long-term Debt and Commercial Paper" for additional  details on the
MEDs Equity Units.)

The remaining items impacting  comparative earnings from continuing operations -
asset sales,  impairment  charges and debt  redemption  charges - are  discussed
below.

During  2004,  KeySpan  sold its  remaining  55% equity  interest in The Houston
Exploration Company ("Houston Exploration"),  an independent natural gas and oil
exploration  company  based in  Houston,  Texas.  We received  cash  proceeds of
approximately  $758 million in two stock transactions that resulted in after-tax
gains of $222.7 million,  or $1.39 per share. The first transaction  occurred in
June 2004 and the  second  transaction  was  completed  in  November  2004.  The
operations  of  Houston   Exploration  were  fully   consolidated  in  KeySpan's
Consolidated Financial Statements during the first five months of 2004, but were
then  accounted  for  on  the  equity  method  of  accounting  after  the  first
transaction reduced our ownership interest below 50%.

Also in 2004,  KeySpan sold its remaining  60.9%  investment  in KeySpan  Energy
Canada Partnership  ("KeySpan  Canada"),  a company that owned certain midstream
natural gas assets in Western Canada. We received cash proceeds of approximately
$255 million in two  transactions  that  resulted in a total  after-tax  gain of
$34.8 million,  or $0.21 per share.  The first  transaction  took place in April
2004 and the second  transaction  was completed in December 2004. The operations
of KeySpan Canada were fully  consolidated in KeySpan's  Consolidated  Financial
Statements during the first three months of 2004, but then were accounted for on
the  equity  method  of  accounting  after  the first  transaction  reduced  our
ownership interest below 50%.

Combined,  these asset sales provided  KeySpan with  approximately $1 billion in
cash  proceeds and  after-tax  earnings of $257.5  million,  or $1.60 per share.
Further,  during 2004,  KeySpan's share of the after-tax  operating  earnings of
Houston Exploration and KeySpan Canada was $83.9 million or $0.52 per share.

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 transactions.

KeySpan  recorded  three  significant  impairment  charges  during  2004:  (i) a
goodwill  impairment  charge  recorded in the Energy  Services  segment;  (ii) a
ceiling test write-down recorded in the Energy Investments  segment; and (iii) a
carrying  value  impairment  charge  also  recorded  in the  Energy  Investments
segment.  These impairment  charges resulted in after-tax  charges to continuing
operations of $62.4 million, or $0.39 per share.


                                       41
<PAGE>


Specifically,  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.  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
was attributable to continuing  operations,  while the remaining $139.9 million,
or $0.87 per share,  was reflected in discontinued  operations.  (See Note 10 to
the   Consolidated   Financial   Statements   "Energy  Services  -  Discontinued
Operations" for additional details on this charge.)

KeySpan's  remaining  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)  in 2004 to  recognize  the  reduced  valuation  of proved
reserves.  (See Note 9 to the Consolidated Financial Statements "Gas Exploration
and Production Property - Depletion," for additional details on this charge.)

In addition to the asset sales noted previously,  in the fourth quarter of 2004,
KeySpan  anticipated  selling its  previous  50%  ownership  interest in Premier
Transmission  Limited  ("Premier"),  a gas pipeline from  southwest  Scotland to
Northern  Ireland.  In the fourth quarter of 2004,  KeySpan  recorded a 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
Premier compared to its carrying value.  This investment was accounted for under
the equity method of accounting in the Energy Investments  segment.  The sale of
Premier was completed in the first quarter of 2005 and resulted in cash proceeds
of approximately $48.1 million and a pre-tax gain of $4.1 million reflecting the
difference from earlier  estimates.  (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 sale.)

The remaining  significant item impacting  comparative  results, as noted above,
was debt  redemption  costs  incurred  in both 2005 and 2004.  In 2005,  KeySpan
redeemed $500 million of 6.15% Notes due in 2006. KeySpan incurred $20.9 million
in call  premiums,  which  were  expensed  and  recorded  in  other  income  and
deductions on the Consolidated  Statement of Income,  and wrote-off $1.3 million
of  previously  deferred  financing  costs.  Further,  KeySpan  accelerated  the
amortization of approximately $11.2 million of previously  unamortized  benefits
associated  with  an  interest  rate  swap  on  these  Notes.   The  accelerated
amortization was recorded as a reduction to interest expense.  The net after-tax
expense of this debt redemption was $6.8 million or $0.04 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 2004,  KeySpan redeemed  approximately $758 million of
various series of outstanding  long-term debt. 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 rate
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 2004 debt
redemption was $29.3 million or $0.18 per share.


                                       42
<PAGE>


The net impact of the above  mentioned  items resulted in a decrease to earnings
from continuing operations of $6.8 million or $0.04 per share for the year ended
December 31, 2005,  compared to a gain of $249.7 million, or $1.55 per share, in
2004.

Earnings Available for Common Stock 2005 vs 2004

Earnings  available  for common  stock also  include  losses  from  discontinued
operations associated with KeySpan's former mechanical contracting subsidiaries;
these  companies  were  discontinued  in the fourth  quarter of 2004 and sold in
early  2005.  In  the  fourth  quarter  of  2004,  KeySpan's  investment  in its
mechanical contracting subsidiaries was written-down to fair value. During 2005,
operating losses  amounting to $4.1 million  after-tax were incurred through the
dates of sale of these companies,  including, but not limited to, costs incurred
for employee related  benefits.  Partially  offsetting these losses was an after
tax-gain of $2.3 million  associated with the related  divestitures,  reflecting
the difference  between the fair value estimates and the financial impact of the
actual sale transactions.  The net income impact of the operating losses and the
disposal gain was a loss of $1.8 million,  or $0.01 per share for the year ended
December 31, 2005.

Further, earnings available for common stock for 2005 include a $6.6 million, or
$0.04 per share, cumulative change in accounting principle charge as a result of
implementing  the accounting  requirements of FASB  Interpretation  No. 47 ("FIN
47")   "Accounting  for  Conditional   Asset   Retirement   Obligations."   This
pronouncement  required  KeySpan to record a liability for the estimated  future
cost associated with the legal obligation to dispose of long-lived assets at the
time of their retirement or disposal date. Upon initial implementation, December
31, 2005, a cumulative  change in  accounting  principle  charge was recorded on
KeySpan's  Consolidated  Statement of Income,  representing the present value of
KeySpan's future retirement obligation. See Note 7 to the Consolidated Financial
Statements "Contractual Obligations, Financial Guarantees and Contingencies" for
further information on this charge.

As  previously  noted,  in 2004 KeySpan  conducted an evaluation of the carrying
value of its  investments in the Energy  Services  segment.  As a result of this
evaluation,  KeySpan  recorded  a loss  in  discontinued  operations  of  $151.0
million,  or $0.94 per  share.  This loss  reflects a $139.9  million  after-tax
impairment  charge  to  reflect  a  reduction  to the  carrying  value of assets
associated with our mechanical  contracting  activities and operating  losses of
$11.1 million.  (See Note 10 to the Consolidated  Financial  Statements  "Energy
Services - Discontinued Operations" for additional details on these items.)

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. 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) earnings from core operations;  (ii) non-core
asset sales recorded in both 2004 and 2003; (iii) impairment charges recorded in
2004; and (iv) debt redemption charges recorded in both 2004 and 2003.


                                       43
<PAGE>


As  indicated  in the table  above,  KeySpan's  earnings  from  core  operations
increased  $25.2 million or $0.14 per share for the twelve months ended December
31, 2004  compared to 2003,  primarily  reflecting  an increase in net  electric
revenues  associated with KeySpan's  Electric Services segment,  as well as from
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.

The remaining items impacting  comparative earnings from continuing operations -
asset sales,  impairment  charges and debt  redemption  charges - are  discussed
below.

As noted previously, during 2004 KeySpan sold its ownership interests in Houston
Exploration and KeySpan  Canada.  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.  Further,  during  2004,  KeySpan's  share of the
after-tax operating earnings of Houston Exploration and KeySpan Canada was $83.9
million or $0.52 per share.

During 2003,  KeySpan completed two non-core asset sales.  KeySpan sold a 39.09%
interest in KeySpan  Canada and a 20%  interest in Taylor NGL LP which owned and
operated two extraction plants 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.  KeySpan's share of
the after-tax  operating earnings of Houston  Exploration and KeySpan Canada was
$98.7 million or $0.62 per share for the twelve months ended December 31, 2003.

Further,  in the  fourth  quarter  of  2003,  we  completed  the sale of a 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 $13.3  million  from the
monetization of 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 transactions.

As previously  noted,  KeySpan  recorded three  significant  impairment  charges
during 2004: (i) a goodwill  impairment  charge  recorded in the Energy Services
segment of $152.4  million  after-tax,  or $0.95 per share,  - $12.6  million of
which was  attributable  to continuing  operations,  while the remaining  $139.9
million, or $0.87 per share, was reflected in discontinued  operations;  (ii) an
after-tax  ceiling test  write-down  of $31.1  million,  or $0.19 per share,  to
recognize the reduced  valuation of proved  reserves  associated  with KeySpan's
wholly-owned gas exploration and production  subsidiaries;  and (iii) a non-cash
impairment  charge of $26.5  million,  - $18.8  million  after-tax  or $0.12 per
share,  recorded in the Energy  Investments  segment  reflecting  the difference
between the anticipated  cash proceeds from the sale of Premier  compared to its
carrying value.


                                       44
<PAGE>


The remaining  significant item noted above is debt redemption costs incurred in
2004 and 2003. As noted previously, in 2004, KeySpan redeemed approximately $758
million of outstanding  long-term debt. The total after-tax expense of this debt
redemption was $29.3 million or $0.18 per share. 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 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 $249.7  million,  or $1.55 per share for the year
ended December 31, 2004, compared to $86.0 million or $0.54 per share in 2003.

Earnings Available for Common Stock 2004 vs 2003

Earnings  available  for common stock for the year ended  December 31, 2004 also
include  losses from  discontinued  operations of $151.0  million,  or $0.94 per
share.  This loss includes  $139.9  million of after-tax  impairment  charges to
reflect a reduction to the carrying  value of assets  associated  with KeySpan's
former  mechanical  contracting  subsidiaries  and  operating  losses  of  $11.1
million.

Earnings  available for common stock for the year ended December 31, 2003,  also
reflect an operating loss from discontinued operations associated with KeySpan's
former mechanical  contracting  subsidiaries of $1.9 million, or $0.01 per share
and 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 KeySpan
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  (the  "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 $37.4  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.)




                                       45
<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 Millions of Dollars, Except Per Share Amounts)                    2005           2004           2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>            <C>            <C>
 Gas Distribution                                                    $ 565.7        $ 579.6        $ 574.3
 Electric Services                                                     342.3          289.8          269.9
 Energy Services
      Operations                                                        (2.7)         (33.9)         (33.0)
      Goodwill impairment charge                                           -          (14.4)             -
 Energy Investments
      Operations of continuing companies                                20.6           24.4           12.5
      Operations of sold companies                                         -          155.0          226.0
      Ceiling test write-down and impairment charge                        -          (74.7)             -
 Eliminations and other                                                (18.1)           9.5           (2.1)
-----------------------------------------------------------------------------------------------------------
 Operating Income                                                      907.8          935.3        1,047.6
-----------------------------------------------------------------------------------------------------------
 Other Income and (Deductions)
      Interest charges                                                (269.3)        (331.3)        (307.7)
      Gain on sale of assets                                             4.1          388.3           13.3
      Cost of debt redemption                                          (20.9)         (45.9)         (24.1)
      Minority interest                                                 (0.4)         (36.8)         (63.9)
      Other income and (deductions)                                     16.6           30.6           42.1
-----------------------------------------------------------------------------------------------------------
                                                                      (269.9)           4.9         (340.3)
-----------------------------------------------------------------------------------------------------------
 Income taxes                                                         (239.3)        (325.5)        (281.3)
-----------------------------------------------------------------------------------------------------------
 Income from Continuing Operations                                     398.6          614.7          426.0
 Loss from discontinued operations                                      (1.8)        (151.0)          (1.9)
 Cumulative change in accounting principles                             (6.6)             -          (37.4)
-----------------------------------------------------------------------------------------------------------
 Net Income                                                            390.2          463.7          386.7
 Preferred stock dividend requirements                                   2.2            5.6            5.8
-----------------------------------------------------------------------------------------------------------
 Earnings for Common Stock                                           $ 388.0        $ 458.1        $ 380.9
-----------------------------------------------------------------------------------------------------------

 Basic Earnings per Share:
    Continuing operations, less preferred stock dividends            $  2.33        $  3.80        $  2.65
    Discontinued operations                                            (0.01)         (0.94)         (0.01)
    Cumulative change in accounting principles                         (0.04)             -          (0.23)
-----------------------------------------------------------------------------------------------------------
                                                                     $  2.28        $  2.86        $  2.41
-----------------------------------------------------------------------------------------------------------
</TABLE>

Operating Income 2005 vs 2004

As indicated in the above table,  operating income  decreased $27.5 million,  or
3%, for the twelve months ended December 31, 2005 compared to the same period of
2004. The comparative operating results reflect the following two items that had
a significant impact on results: (i) operating results of non-core  subsidiaries
recorded in 2004;  offset by (ii) impairment  charges recorded in 2004. As noted
earlier,  during  2004  KeySpan  held  equity  ownership  interests  in  Houston
Exploration and KeySpan  Canada.  For the twelve months ended December 31, 2004,
KeySpan's  share of the combined  operating  income of Houston  Exploration  and
KeySpan Canada was $155.0 million. KeySpan sold its remaining ownership interest
in these  non-core  operations in the fourth  quarter of 2004.  Offsetting  this
income to some extent were pre-tax non-cash  impairment charges of $89.1 million
recorded  in 2004.  As noted  earlier,  KeySpan  recorded  the  following  three


                                       46
<PAGE>


impairment charges during 2004: (i) a goodwill impairment charge recorded in the
Energy Services segment attributable to continuing  operations of $14.4 million;
(ii) a ceiling  test  write-down  of $48.2  million  to  recognize  the  reduced
valuation  of  proved  reserves  associated  with  KeySpan's   wholly-owned  gas
exploration and production subsidiaries;  and (iii) a non-cash impairment charge
of $26.5 million also recorded in the Energy Investments  segment reflecting the
difference  between  the  anticipated  cash  proceeds  from the sale of  Premier
compared to its carrying value.

The combined impact of the non-core  operating income recorded in 2004 offset by
the impairment  charges  contributed  $65.9 million to operating  income for the
twelve months ended  December 31, 2004.  KeySpan's core  businesses,  therefore,
posted an increase in operating  income of $38.4  million for the twelve  months
ended  December  31,  2005,  compared  to the same  period  of  2004,  primarily
reflecting  an  increase  of $52.5  million in the  Electric  Services  segment,
partially offset by a $13.9 million  decrease in the Gas  Distribution  segment.
The favorable  results from KeySpan's  electric services  operations  reflect an
increase in net  electric  revenues as a result of higher  electric  prices that
were  due,  in  part,  to the warm  weather  during  the  summer  of  2005.  Gas
distribution  results,  however,  were  adversely  impacted by higher  operating
expenses,  primarily  due to an  increase  in the  provision  for  uncollectible
accounts  receivable  as a result  of higher  gas  costs and by higher  property
taxes. For the most part, the beneficial impact on comparative  operating income
from lower net operating  losses  incurred at the Energy Services  segment,  was
offset by an  increase  in  expenses  residing  at the  holding  company  level.
Further,  in 2004  KeySpan  reached a settlement  with certain of 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 expense.

Other income and (deductions)  reflects interest charges,  costs associated with
debt redemptions,  income from subsidiary stock transactions,  minority interest
charges and other miscellaneous  items. For the twelve months ended December 31,
2005,  other income and  (deductions)  reflects a net expense of $269.9  million
compared to income of $4.9  million for the twelve  months  ended  December  31,
2004.  This  unfavorable  variation  of $274.8 is due to higher gains from asset
sales recorded in 2004 compared to 2005 of $384.2 million,  offset by a decrease
in  interest  charges of $62.0  million,  lower debt  redemption  costs of $25.0
million and the  absence of minority  interest  expenses of $36.4  million.  The
following is a discussion of these items.

As noted earlier,  in the first quarter of 2005,  KeySpan  finalized its sale of
Premier.  The final sale of Premier  resulted in a pre-tax  gain of $4.1 million
reflecting  the difference  from earlier  estimates and what was recorded in the
first quarter of 2005.  For the twelve months ended  December 31, 2004,  KeySpan
realized  pre-tax income of $388.3 million from  subsidiary  stock  transactions
associated with Houston Exploration and KeySpan Canada, as discussed earlier.

Interest  expense  decreased $62.0 million,  or 19%, for the twelve months ended
December 31, 2005, compared to the same period of 2004,  reflecting the benefits
attributable  to  recent  debt  redemptions,  as  well as the  sale  of  Houston
Exploration and KeySpan Canada. In addition,  as noted earlier,  in 2005 KeySpan
redeemed  $500  million  6.15%  Series Notes due 2006.  KeySpan  incurred  $20.9
million  in  call  premiums,  wrote-off  $1.3  million  of  previously  deferred
financing costs and accelerated the amortization of approximately  $11.2 million
of  previously  unamortized  benefits  associated  with an interest rate swap on
these bonds.  The  accelerated  amortization  of the interest  rate swap and the
write-off of previously  deferred  financing costs reduced  interest  expense in
2005 by $9.9 million.


                                       47
<PAGE>


In 2004,  KeySpan  redeemed  approximately  $758  million of  various  series of
outstanding  debt and incurred $45.9 million in call premiums and wrote-off $8.2
million of previously  deferred  financing costs. The net impact of the 2005 and
2004 debt redemptions lowered comparative interest expense by $18.1 million.

For the year ended December 31, 2004 other income and (deductions) also includes
the  effects of  minority  interest  of $36.8  million  related to our  previous
majority ownership interests in Houston Exploration and KeySpan Canada. Finally,
other income and  (deductions)  for the year ended  December 31, 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,  a 250 MW combined cycle  generating
facility  located at the  Ravenswood  site,  as well as a $5.5  million  foreign
currency gain.

Income  taxes  decreased  $86.2  million  for the year ended  December  31, 2005
compared to last year due,  for the most part,  to lower  pre-tax  earnings.  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 $12 million  related to the  repatriation of earnings from
KeySpan's foreign  investments;  and (iii) the beneficial tax treatment afforded
the stock transaction with Houston Exploration.

As noted  earlier,  earnings  available  for  common  stock  for the year  ended
December 31, 2005,  also includes  losses of $1.8  million,  or $0.01 per share,
from  discontinued  operations,  as well as a $6.6  million,  or $0.04 per share
cumulative change in accounting principles charge. Earnings available for common
stock for the year ended December 31, 2004,  includes  losses of $151.0 million,
or $0.94 per share, from discontinued operations.

As a result of the items discussed  above,  earnings  available for common stock
were $388.0  million,  or $2.28 per share for the year ended  December 31, 2005,
compared to $458.1 million, or $2.86 per share realized in 2004.

Operating Income 2004 vs 2003

Operating income  decreased $112.3 million,  or 11%, 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
Investments  segment as a result of  KeySpan's  reduced  ownership  interest  in
Houston Exploration and KeySpan Canada during the latter half of 2004. KeySpan's
lower ownership level in these former subsidiaries reduced comparative operating
income by $71.0 million. 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  associated with our previous  investment in
Premier.  Further,  the decrease in operating  income reflects the $14.4 million
non-cash goodwill impairment charge recorded in the Energy Services segment. The
combined impact of the decrease in non-core  operating income and the impairment
charges  recorded in 2004 reduced  operating  income for the twelve months ended


                                       48
<PAGE>


December 31, 2004, by $160.1  million.  KeySpan's  core  businesses,  therefore,
posted an increase in operating  income of $47.8  million for the twelve  months
ended  December  31,  2004  compared  to the  same  period  of  2003,  primarily
reflecting  increases of $19.9 million in the Electric  Services  segment,  $5.3
million in the Gas  Distribution  segment and $11.9 million from the  continuing
operations in the Energy Investments segment.

The increase in comparative operating income in the Electric Services segment in
2004  primarily  reflects  higher  net  electric  margins  associated  with  the
Ravenswood  Expansion.  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. In 2003, we recorded $15.1
million in gains from  property  sales,  primarily the sale of 550 acres of real
property  located on Long  Island,  that were  recorded in the Gas  Distribution
segment.  The continuing  operations in the Energy Investments  segment realized
higher  earnings  from  the sale of  property,  as well as from an  increase  in
earnings from gas pipeline investments and generally lower administrative costs.
(See the discussion under the caption "Review of Operating Segments" for further
details on each segment.)

Other income and (deductions)  reflects interest charges,  costs associated with
debt redemptions,  income from subsidiary stock transactions,  minority interest
charges and other miscellaneous  items. For the twelve months ended December 31,
2004, other income and (deductions) reflects a net gain of $4.9 million compared
to a net expense of $340.3  million for the twelve  months  ended  December  31,
2003.  This  favorable  variation of $345.2  million is due to higher gains from
asset  sales  recorded in 2004  compared  to 2003 of $375.0  million and a lower
minority interest adjustment of $27.1 million, offset by an increase in interest
charges of $23.6 million and higher debt redemption costs of $21.8 million.  The
following is a discussion of these items.

As noted  earlier,  for the twelve  months  ended  December  31,  2004,  KeySpan
realized  pre-tax income of $388.3 million from  subsidiary  stock  transactions
associated  with  Houston  Exploration  and  KeySpan  Canada.  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 $13.3 million  associated with these  transactions.  Further,  the lower
ownership level in Houston Exploration and KeySpan Canada in 2004 resulted in an
associated decrease in the minority interest adjustment of $27.1 million.

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,  discussed  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.")


                                       49
<PAGE>


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. In March 2003, we
redeemed 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.

As noted previously, during 2004, KeySpan redeemed approximately $758 million of
outstanding  long-term debt and recorded $45.9 million in debt redemption costs.
In 2003, KeySpan incurred debt redemption costs of $24.1 million associated with
(i) the redemption of approximately $447 million of outstanding promissory notes
issued to LIPA in connection with the KeySpan/LILCO  business  combination;  and
(ii) Houston  Exploration's debt redemption costs of $5.9 million to retire $100
million  8.625%  Notes.  The  operating  results  for Houston  Exploration  were
consolidated in 2003.

Other  income  and  (deductions)  for 2004 also  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) for 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.

(See Note 7 to the Consolidated Financial Statements,  "Contractual Obligations,
Financial Guarantees and Contingencies" for additional information regarding the
sale/leaseback transaction.)

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 $12  million  related  to the  repatriation  of  earnings  from
KeySpan's foreign  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 our regulated  utilities in
Massachusetts. 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.


                                       50
<PAGE>


As noted  earlier,  earnings  available  for  common  stock  for the year  ended
December 31, 2004, also included  losses of $151.0 million,  or $0.94 per share,
from discontinued  operations.  Earnings available for common stock for the year
ended December 31, 2003, included a charge for a cumulative change in accounting
principles  of  $37.4  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.

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.


                                       51
<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 Millions of Dollars)                                                           2005               2004              2003
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>                <C>               <C>
Revenues                                                                        $ 5,390.1          $ 4,407.3         $ 4,161.3
Cost of gas                                                                       3,607.0            2,664.7           2,444.5
Revenue taxes                                                                        65.8               73.3              90.5
-------------------------------------------------------------------------------------------------------------------------------
Net Gas Revenues                                                                  1,717.3            1,669.3           1,626.3
-------------------------------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                                                       727.0              672.5             659.9
   Depreciation and amortization                                                    276.9              276.5             259.9
   Operating taxes                                                                  147.8              140.7             147.3
-------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                                          1,151.7            1,089.7           1,067.1
-------------------------------------------------------------------------------------------------------------------------------
Gain on the sale of property                                                          0.1                  -              15.1
Operating Income                                                                $   565.7          $   579.6         $   574.3
-------------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH)                                          323,347            324,549           328,073
Transportation - Electric  Generation (MDTH)                                       25,076             27,656            34,778
Other Sales (MDTH)                                                                187,805            155,992           158,722
Warmer (Colder) than Normal - New York & Long Island                                (1.0%)             (1.0%)            (8.0%)
Warmer (Colder) than Normal - New England                                           (8.6%)             (6.8%)           (10.0%)
-------------------------------------------------------------------------------------------------------------------------------
</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 2005 vs 2004

Operating  income  decreased  $13.9 million,  or 2%, for the twelve months ended
December 31, 2005, compared to the same period last year due to higher operating
expenses.  Operating expenses  increased $62.0 million  reflecting  primarily an
increase in the  provision  for  uncollectible  accounts  receivable  and higher
property taxes totaling $45.8 million. Partially offsetting the higher operating
expenses was an increase of $48.0 million in net gas revenues (revenues less the
cost of gas and associated  revenue taxes) resulting from customer additions and
oil-to-gas  conversions in our firm gas sales market, as well as from higher net
gas revenues in our large-volume heating markets.

Net Revenues

Net gas revenues from our gas distribution  operations  increased $48.0 million,
or 3%, for the twelve  months  ended  December  31,  2005,  compared to the same
period  last year.  Net gas  revenues  benefited  from  customer  additions  and
oil-to-gas conversions in our firm gas sales market (residential, commercial and
industrial  customers),  as  well  as  from  higher  net  gas  revenues  in  our
large-volume  heating  and  interruptible  (non-firm)  markets.  As  measured in
heating  degree  days,  weather in 2005 in our New York and New England  service
territories was  approximately  1.0% and 8.6% colder than normal,  respectively.
Compared  to 2004,  weather in 2005 was 1.2%  colder in  KeySpan's  New  England
service  territory,  while weather was consistent  between years in the New York
service territory.


                                       52
<PAGE>


Net revenues from firm gas customers  (residential,  commercial  and  industrial
customers)  increased  $24.3  million for the twelve  months ended  December 31,
2005,  compared to the same period last year.  Customer additions and oil-to-gas
conversions,  net of attrition and conservation,  added $25.1 million to net gas
revenues.  Further,  we  realized a benefit  of $3.8  million as a result of the
Boston Gas Company's  Performance Based Rate Plan (the "Plan") that was approved
by the Massachusetts  Department of  Telecommunications  and Energy ("MADTE") in
2003.  The Plan provides for firm gas sales rates to be adjusted each year based
on an inflation factor offset by a productivity  factor.  (See the caption under
"Regulation  and  Rate  Matters"  for  further  information  regarding  the rate
filing.)

Offsetting,  to some extent, the beneficial impact of the customer additions and
oil-to-gas  conversions  was the adverse impact to comparative  net gas revenues
from the additional billing day last year due to the leap year. In 2004, KeySpan
realized $5.7 million in additional net gas revenues from the additional billing
day. Further,  KeySpan earned $8.7 million less in regulatory incentives for the
twelve months ended December 31, 2005, compared to the same period last year.

Also  included in net revenues is the recovery of certain  regulatory  items and
certain taxes that added $6.6 million to net revenues.  However, the recovery of
these  items  through  revenues  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.  Firm gas distribution rates for KEDNY, KEDLI
and KEDNE in 2005,  other than for the recovery of gas costs and as noted,  have
remained substantially unchanged from rates charged in 2004.

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.  However,  the gas  distribution
operations  of  our  New  England  based  subsidiaries  do not  have  a  weather
normalization  adjustment.  To  mitigate  the effect of  fluctuations  in normal
weather  patterns  on KEDNE's  results of  operations  and cash  flows,  weather
derivatives  were in  place  for the  2004/2005  and  2005/2006  winter  heating
seasons.  These financial  derivatives  afforded KeySpan some protection against
warmer  than  normal  weather.  As a  result  of the  weather  fluctuations  and
financial  weather  derivatives,  weather had a $3.2 million favorable impact on
comparative  net  gas  revenues.  (See  Note  8 to  the  Consolidated  Financial
Statements  "Hedging,  Derivative  Financial  Instruments  and Fair  Values" for
further information on derivative transactions.)

In our large-volume heating and 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  $23.7 million  during the twelve months ended December
31, 2005,  compared to the same period last year,  primarily  reflecting  higher
pricing.  Further,  since weather during January 2004 was  significantly  colder
than normal, KeySpan interrupted service to a segment of its dual-fuel customers
for a number of days during the month, as permitted under its tariff,  to ensure
reliable service to firm customers. The majority of interruptible profits earned
by KEDLI and KEDNE are returned to firm customers as an offset to gas costs.


                                       53
<PAGE>


Firm Sales, Transportation and Other Sales Quantities

Both actual  firm gas sales and  transportation  quantities,  as well as weather
normalized  sales  quantities  for the twelve  months  ended  December 31, 2005,
remained consistent with those quantities realized in 2004. 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
transportation 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.  The  increase in these  sales  quantities  for the
twelve  months  ended  December  31,  2005  compared  to the same period of 2004
reflects  higher  off-system  sales.  The majority of these  profits  earned are
returned to firm customers as an offset to gas costs. From April 1, 2002 through
March 31, 2005, we had an agreement  with Coral  Resources,  L.P.  ("Coral"),  a
subsidiary of Shell Oil Company,  under which Coral assisted in the origination,
structuring, valuation and execution of energy-related transactions on behalf of
KEDNY and KEDLI.  Upon the  expiration  of this  agreement,  these  services are
provided by 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. A new three
year  agreement  has been  negotiated  with Merrill  Lynch to provide  portfolio
management  services to KeySpan's  Massachusetts gas distribution  subsidiaries.
This  agreement is pending MADTE  approval.  KeySpan will provide these services
internally for its New Hampshire gas distribution subsidiary, EnergyNorth.

Purchased Gas for Resale

The  increase  in gas costs for the  twelve  months  ended  December  31,  2005,
compared  to the same period of 2004,  of $942.3  million,  or 35%,  reflects an
increase of 23% in the price per  dekatherm of gas  purchased for firm gas sales
customers,  as  well  as an  increase  in  the  quantity  of gas  purchased  for
large-volume  heating and interruptible  (non-firm)  customers.  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 resale to firm sales  customers  and gas costs billed to firm sales
customers  are  deferred  and  refunded  to or  collected  from  customers  in a
subsequent period.

Operating Expenses

For the twelve  months ended  December 31, 2005,  operating  expenses  increased
$62.0  million,  or 6% compared to the same  period  last year.  Operations  and
maintenance  expense  increased  $54.5 million,  or 8%, in 2005 compared to 2004
primarily due to an increase of $38.7 million in the provision for uncollectible
accounts as a result of increasing  gas costs and the adverse impact from recent
collection  experience.  Further,  the gas distribution  operations  realized an
increase in insurance and regulatory fees, as well as postretirement expenses in
2005 compared to 2004. In 2004, KeySpan recognized 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 ( the "Medicare Act") and  implementation of Financial


                                       54
<PAGE>


Accounting  Standards Board Staff Position ("FSP") 106-2. In addition,  in 2004,
Boston Gas  reached an  agreement  with an  insurance  carrier  for  recovery of
previously  incurred  environmental  expenditures.   Insurance  and  third-party
recoveries,  after  deducting  legal fees, are shared between Boston Gas and its
firm gas customers as provided under a previously  issued MADTE rate order. As a
result of this insurance settlement, Boston Gas recorded a $5 million benefit to
operations and maintenance expense.

Comparative  operating  taxes  increased $7.1 million due to the expiration of a
five-year property tax assessment  agreement with New York City, as well as to a
$2.5 million property tax refund received in 2004. Higher  depreciation  charges
of $4.5 million  reflecting  the  continued  expansion  of the gas  distribution
system were offset by lower regulatory amortization charges of $4.1 million.

In  December  2005,  Boston Gas  received a MADTE  order  permitting  regulatory
recovery  of the 2004  gas  cost  component  of bad  debt  write-offs.  This was
approved for full recovery as an exogenous cost  effective  November 1, 2005. In
addition,  effective  January 1, 2006,  Boston Gas is permitted to fully recover
the gas cost component of bad debt write-offs through its cost-of-gas adjustment
clause rather than filing for recovery as an exogenous  cost. We have  reflected
both of these favorable  recovery  mechanisms in our December 31, 2005 Allowance
for Doubtful Accounts reserve  requirement and related expense.  Boston Gas also
plans to request  full  recovery,  as an  exogenous  cost,  of the 2005 gas cost
component of bad debt write-offs beginning November 1, 2006.

Executive Summary

Operating Income 2004 vs 2003

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 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  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.

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 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 2003 in our New  England  service
territory.


                                       55
<PAGE>


Net revenues from firm gas customers  (residential,  commercial  and  industrial
customers) increased $40.8 million for the twelve months ended December 31, 2004
compared to the same period of 2003. As previously mentioned, the MADTE approved
a $27 million  base rate  increase  for Boston Gas,  which  became  effective on
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.)  Customer  additions  and  oil-to-gas  conversions,  net  of
attrition and conservation,  added $8.0 million to net gas revenues. Further, we
realized a $5.7 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.

Also  included in net gas revenues is the  recovery of property  taxes that were
$1.0 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 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.

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.  However,  the gas  distribution
operations  of  our  New  England  based  subsidiaries  do not  have  a  weather
normalization  adjustment.  To mitigate  the effect of  fluctuations  in weather
patterns on KEDNE's  results of operations and cash flows,  weather  derivatives
were in place for the 2003/2004  and 2004/2005  winter  heating  seasons.  These
financial  derivatives  afforded  KeySpan some  protection  against  warmer than
normal weather. As a result of weather fluctuations year-to-year,  offset by the
benefits  of the  financial  weather  derivatives,  weather  had a $2.9  million
unfavorable impact on comparative net gas revenues.

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 KEDLI and KEDNE are returned to firm customers
as an offset to gas costs.

Firm Sales, Transportation and Other Sales 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 service territories during 2004. 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.


                                       56
<PAGE>


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.

Operating Expenses

Total  operating  expenses for the year ended December 31, 2004 increased  $22.6
million,  or 2%, compared to 2003,  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 $3
million,  net of amounts subject to regulatory  deferral  treatment,  associated
with the  implementation  of the  Medicare Act and  implementation  of Financial
Accounting  Standards Board Staff Position ("FSP") 106-2. In addition,  in 2004,
Boston Gas  reached a  settlement  with an  insurance  carrier  for  recovery of
previously  incurred  environmental  expenditures.   Insurance  and  third-party
recoveries,  after  deducting  legal fees, are shared between Boston Gas and its
firm gas customers  under a previously  issued MADTE rate order.  As a result of
this  insurance  settlement,  Boston  Gas  recorded  a  $5  million  benefit  to
operations and maintenance expense.

Higher  depreciation  and  amortization  expense in 2004  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.

Sale of Property

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

Gas Supply and Pricing

KeySpan has  adequate  gas supply  available  to meet its gas load demand in its
service  territories  for the 2005/2006  winter  heating season as KeySpan's gas
storage was 100% full at the start of the winter heating season. The current gas
rate  structure  of  each  of our  gas  distribution  utilities  includes  a gas
adjustment clause,  pursuant to which gas costs are recovered in billed sales to
regulated  firm gas  sales  customers.  Although  KeySpan  is  allowed  to "pass
through" the cost of gas to its  customers,  management  is  concerned  with the
rising  natural gas prices and the related  impact on  customers'  gas bills and
recovery  of  customer  accounts  receivable.  As  noted,  KeySpan  has  already
experienced  an increase in bad debt expense and an increase in collection  lag.
Also,  it is likely  that the high gas prices  will lead to an increase in price
elasticity possibly resulting in an increase in customer  conservation  measures
and attrition.  The recent MADTE order permitting Boston Gas regulatory recovery
of the gas cost component of net bad debt write-offs should help to mitigate the
increase in bad debt expense.


                                       57
<PAGE>


With our strategy of having KeySpan's storage  facilities 100% full at the start
of the  heating  season  and  our  use of  financial  derivatives,  KeySpan  has
effectively  hedged  the price of  approximately  two-thirds  of the gas  supply
needed to serve its customers during the upcoming  2005/2006 winter.  This helps
mitigate the impact from rising natural gas prices on customers'  winter heating
gas bills. Further, KeySpan has programs in place to help customers manage their
gas bills, such as balanced billing plans, deferred payment arrangements and the
low income home energy assistance  program,  which we supported the expansion of
through  the Energy  Act.  Management  believes  that these  measures  will help
mitigate the impact of rising gas prices on customers' bills.

Other Matters

We remain committed to our ongoing gas system expansion  strategies.  We believe
that  significant  growth  opportunities  exist  on Long  Island  and in our New
England service territories, as well as continued growth in the New York service
territory,  despite  the rising gas  prices.  We  estimate  that on Long  Island
approximately 37% of the residential and multi-family markets, and approximately
60% 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 approximately 60% of
the commercial market,  currently use natural gas for space heating purposes. We
will continue to seek growth, in all our market segments,  through the expansion
of our gas distribution  system for new  construction and to penetrate  existing
communities  where  no  distribution  system  exists,  as  well as  through  the
conversion of residential homes from oil-to-gas for space heating purposes where
natural  gas  is  already  in the  home  for  other  uses  and  the  pursuit  of
opportunities to grow multi-family, industrial and commercial markets.

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.  Once in  service,  the  pipeline  is
expected  to  transport  up to 260,000 DTH of natural gas to the Long Island and
New York City energy  markets,  enough  natural gas to heat  600,000  homes.  In
addition, during 2004 KeySpan acquired a 21% interest in the Millennium Pipeline
development  project  which is  anticipated  to  transport  up to 525,000 DTH of
natural  gas a day to the  Algonquin  pipeline.  KEDLI has  executed a Precedent
Agreement for 150,000 DTH of natural gas per day of transportation capacity from
the Millennium  Pipeline system,  increasing to 200,000 DTH in the third year of
the pipeline  being in service.  These  pipeline  projects will allow KeySpan to
diversify the geographic sources of its gas supply. See the discussion under the
caption "Energy Investments" for additional information regarding these pipeline
projects.


                                       58
<PAGE>


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  Generating  Station" which comprises the Ravenswood
Facility  and  Ravenswood  Expansion)  and the counties of Nassau and Suffolk on
Long Island. In addition, through long-term contracts of varying lengths, 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 "1998 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 "1998  PSA");  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 "1998 EMA"). The 1998 MSA, 1998
PSA and 1998  EMA all  became  effective  on May 28,  1998 and are  collectively
referred to herein as the "1998 LIPA Agreements."

On February 1, 2006,  KeySpan and LIPA  entered into (i) an amended and restated
Management  Services Agreement (the "2006 MSA"),  pursuant to which KeySpan will
continue to operate and  maintain  the electric T&D System owned by LIPA on Long
Island;  (ii) a new Option and  Purchase  and Sale  Agreement  (the "2006 Option
Agreement"), to replace the Generation Purchase Rights Agreement as amended, the
("GPRA"),  pursuant to which LIPA had the option,  through December 15, 2005, to
effectively  acquire  substantially  all of the electric  generating  facilities
owned by KeySpan on Long  Island;  and (iii) a Settlement  Agreement  (the "2006
Settlement   Agreement")   resolving  outstanding  issues  between  the  parties
regarding the 1998 LIPA Agreements.  The 2006 MSA, the 2006 Option Agreement and
the 2006 Settlement  Agreement are collectively  referred to herein as the "2006
LIPA  Agreements".  (For a further  discussion on these LIPA  agreements see the
discussion under the caption  "Electric  Services - LIPA Agreements" and Note 11
to the Consolidated  Financial  Statements "2006 LIPA Settlement.") The Electric
Services  segment also provides  retail  marketing of  electricity to commercial
customers.

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 Millions of Dollars)                                         2005            2004            2003
-------------------------------------------------------------------------------------------------------
<S>                                                          <C>             <C>            <C>
Revenues                                                     $  2,047.3      $  1,738.7     $  1,606.1
Purchased fuel                                                    751.4           539.6          464.8
-------------------------------------------------------------------------------------------------------
Net Revenues                                                    1,295.9         1,199.1        1,141.3
-------------------------------------------------------------------------------------------------------
Operating Expenses
   Operations and maintenance                                     684.5           653.3          658.6
   Depreciation                                                    91.7            88.3           67.2
   Operating taxes                                                178.6           169.7          145.6
-------------------------------------------------------------------------------------------------------
Total Operating Expenses                                          954.8           911.3          871.4
-------------------------------------------------------------------------------------------------------
Gain on the sale of property                                        1.2             2.0              -
Operating Income                                             $    342.3      $    289.8     $    269.9
-------------------------------------------------------------------------------------------------------
Electric sales (MWH)*                                         6,364,279       6,232,190      4,738,331
Capacity(MW)*                                                     2,450           2,450          2,200
Summer cooling degree days                                        1,472           1,045            988
-------------------------------------------------------------------------------------------------------
</TABLE>
*Reflects the operations of the Ravenswood Generating Station only.


                                       59
<PAGE>


Executive Summary

Operating Income 2005 vs 2004

For the twelve months ended December 31, 2005,  operating income increased $52.5
million,  or 18%,  compared  to last year,  primarily  due to an increase in net
revenues from the  Ravenswood  Generating  Station of $78.7 million  mainly as a
result of  improved  pricing,  partially  offset  by an  increase  in  operating
expenses associated with the Ravenswood  Generating Station of $11.8 million, as
well as lower net revenues  associated with KeySpan's retail electric  marketing
activities of $7.6 million.

Net Revenues

Total electric net revenues realized during the twelve months ended December 31,
2005,  were $96.8 million,  or 8% higher than such revenues  realized during the
corresponding period last year.

For the  year  ended  December  31,  2005,  net  revenues  from  the  Ravenswood
Generating Station increased $78.7 million,  or 22%, compared to the same period
last  year  reflecting  higher  energy  margins  of  $66.0  million,  as well as
increased capacity revenues of $12.7 million.  The increase in capacity revenues
reflects  the  operation  of the  Ravenswood  Expansion  which  went  into  full
commercial operation in May 2004, as well as load growth in New York City.

The increase in energy  margins for 2005 reflects an increase of 45% in realized
"spark-spreads"  (the selling price of electricity  less the cost of fuel,  plus
hedging  gains or  losses),  as well as from an  increase  of 2% in the level of
megawatt  hours  ("MWh")  sold  into the New York  Independent  System  Operator
("NYISO") energy market. These favorable energy results were primarily driven by
the pricing differential between number 6-grade fuel oil and natural gas used in
the Ravenswood  Generating  Station in 2005. Due to the dual-fuel  nature of the
Ravenswood  Generating  Station,  KeySpan  was able to take  advantage  of their
ability to switch to cheaper fuel as the gap between number 6 grade fuel oil and
gas prices spread during the latter part of the 2005 summer.  The two hurricanes
which  occurred  this  past  summer  in the  Gulf  Coast  of the  United  States
contributed  to the gap between  number 6-grade fuel oil and natural gas prices.
Further,  in 2005 KeySpan received $9.2 million from the NYISO to settle billing
issues  regarding  the sale of  energy  provided  by the  Ravenswood  Generating
Station  to the NYISO in May 2000.  Weather  for 2005,  as  measured  in cooling
degree days, was 40% warmer than last year and 28% warmer than normal.

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  Generating Station.  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  Generating  Station.  These derivative  instruments  resulted in
hedging losses, which are reflected in net electric margins, of $16.0 million in
2005  compared to hedging gains of $23.0  million in 2004.  The results  derived
from  KeySpan's  hedging  strategy are reflected in the  calculation of realized
spark-spreads.  (See Note 8 to the Consolidated  Financial  Statements "Hedging,
Derivative  Financial   Instruments  and  Fair  Values"  as  well  as  Item  7A.
Quantitative  and  Qualitative   Disclosures   about  Market  Risk  for  further
information on KeySpan's hedging strategies.)


                                       60
<PAGE>


The rules and  regulations  for  capacity,  energy sales and the sale of certain
ancillary  services to the NYISO energy markets continue to evolve and there are
several  matters  pending with the FERC.  See the  discussion  under the caption
"Market  and Credit Risk  Management  Activities"  for further  details on these
matters.

Net revenues for the twelve  months  ended  December 31, 2005,  from the service
agreements with LIPA,  including the power purchase  agreements  associated with
two  electric  peaking  facilities,  increased  $25.7  million  compared  to the
corresponding  period of 2004.  The  increase  is due,  in part,  to recovery of
operating  expenses billed to LIPA of approximately $14 million and the recovery
of depreciation  charges and property taxes of approximately  $8 million.  These
recoveries had no impact on operating income since actual expenses  increased by
a like amount. The remaining increase primarily reflects an increase in emission
credits  earned  and  variable  revenues,  which  are  a  function  of  electric
generation  output.  In 2005 and 2004 we earned $16.4  million  associated  with
non-cost  performance  incentives  provided for under these  agreements.  (For a
description  of the LIPA  Agreements  and  power  purchase  agreements,  see the
discussion under the caption "Electric Services - LIPA Agreements.")

Net revenues  associated  with KeySpan's  retail electric  marketing  activities
decreased  $7.6  million  in  2005  compared  to  2004,  due  to  a  significant
curtailment  in these  activities.  KeySpan has  terminated  all  indexed  price
contracts  and has elected to maintain  only its fixed  priced  contracts.  As a
result,  the retail electric  marketing  business has  approximately 40 MW under
contract.

Operating Expenses

For the twelve  months ended  December 31, 2005,  operating  expenses  increased
$43.5  million,  or 5%,  compared to the same period last year.  Operations  and
maintenance  expense increased $31.2 million, or 5% over last year reflecting an
increase of $7.5 million in operating lease costs  associated with our financing
arrangement  for the  Ravenswood  Expansion,  as well as an increase in overhaul
work and  plant  retirement  costs  associated  with the  Ravenswood  Generating
Station amounting to approximately $8 million.  The remaining  increase reflects
operating costs billed to LIPA of approximately $14 million.

Depreciation  expense  and  operating  taxes  increased  $12.3  million  in 2005
compared to 2004. Of this amount,  approximately  $8 million is associated  with
KeySpan's Long Island based electric  generating units and are fully recoverable
from  LIPA,  as noted  above.  The  remaining  increase  in these  line items is
associated with the Ravenswood Generating Station.


                                       61
<PAGE>


Executive Summary

Operating Income 2004 vs 2003

Operating  income  increased  $19.9 million for the twelve months ended December
31, 2004  compared to the same period in 2003,  due  primarily to an increase in
net revenues from the Ravenswood Generating Station of $53.8 million,  partially
offset by higher depreciation expense and operating taxes. In addition, in 2004,
KeySpan recognized a gain of $2.0 million on the sale of a parcel of land in Far
Rockaway, Queens, to LIPA.

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  Generating Station 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 in 2004,  compared to 2003 primarily reflects the operation of
the Ravenswood Expansion.

The increase in energy  margins for the twelve  months ended  December 31, 2004,
reflects a 32% increase in the level of MWh's sold into the NYISO energy market,
as well as an increase of 9% in realized  spark-spreads.  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 2003,  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.

As noted, 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  Generating Station.  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  Generating  Station.  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.

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.


                                       62
<PAGE>


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

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 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 classification 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  Generating  Station,  as well as higher
postretirement  costs, which, for the most part, offset the beneficial impact of
FIN  46.  (See  Note 7 to the  Consolidated  Financial  Statements  "Contractual
Obligations,  Financial  Guarantees and Contingencies" for an explanation of the
Ravenswood Master Lease.)

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.

Other Matters

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 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 power from a non-Long Island source of
between  250 to 600 MW of  electricity  by no  later  than the  summer  of 2007.
KeySpan  filed a proposal in response  to LIPA's  RFP.  In 2004,  LIPA  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


                                       63
<PAGE>


distribution  network. In addition,  given the intense public pressure to reduce
emissions  from  existing  generating  facilities,  development  of the Melville
project is possible as a means to "virtually  re-power"  older,  less  efficient
generating units. Specifically, KeySpan believes that it would be able to reduce
emissions on Long Island in a cost  effective  manner by developing the Melville
project and retiring an older, less efficient generating facility. We have begun
discussions  with LIPA  regarding  this  proposal.  At December 31, 2005,  total
capitalized  costs  associated  with the siting,  permitting and  procurement of
equipment for the Melville facility were $61.2 million.

In March  2005,  LIPA issued a RFP to provide  system  power  supply  management
services beginning May 29, 2006 and fuel management  services for certain of its
peaking  generating  units  beginning  January 1, 2006. A KeySpan  subsidiary is
currently performing these services.  KeySpan submitted a bid in response to the
new RFP in April 2005.  LIPA was scheduled to select a service  provider in June
2005, but has deferred such decision at this time. Pending LIPA's  determination
on the RFP, the service  agreements  between  KeySpan and LIPA which provide for
these  services have been  extended to December 31, 2006. We cannot  predict the
outcome or the timing of any decisions by LIPA on this matter at this time.

Also,  in March 2005,  the New York Power  Authority  ("NYPA")  issued a RFP for
long-term  New York City  capacity and energy to meet the needs of its customers
at prices that are economical, stable and predictable over the long run. In June
2005,  KeySpan submitted a non-binding bid in response to NYPA's RFP in which we
proposed to construct a 500 MW, combined cycle, natural gas fired power plant to
be located in New York City,  which could  provide  energy and capacity to NYPA.
The proposed  facility could be in commercial  operation by June 2009. We cannot
predict  the  outcome or the timing of any  decisions  by NYPA on this matter at
this time.

As part of our growth strategy, we continually evaluate the possible acquisition
and development of additional generating facilities in the Northeast, as well as
other  assets to  complement  our core  operations.  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.

Currently, the NYISO's New York City local reliability rules require that 80% of
the  electric  capacity  needs  of  New  York  City  be  provided  by  "in-City"
generators.  On February 6, 2006, the NYISO  Operating  Committee  increased the
"in-City" generator  requirement to 83% beginning in May 2006 through the period
ending on April 2007, based in part on the statewide  reserve margin of 118% set
by the New York State  Reliability  Council.  On February 16, 2006 an appeal was
filed with the NYISO  Management  Committee  requesting  that the  February  6th
decision be rejected and that the "in-City" requirement be increased to a larger
percentage  than 83%. A vote on this  appeal is  expected  to occur at the NYISO
Management Committee meeting scheduled for February 28, 2006.

Our Ravenswood  Generating  Station is an "in-City"  generator.  As the electric
infrastructure  in New York City and the  surrounding  areas continues to change
and evolve and the demand for electric power increases,  the "in-City" generator
requirement  could be further  modified.  Construction of new  transmission  and
generation  facilities may cause significant  changes to the market for sales of
capacity,  energy and ancillary services from our Ravenswood Generating Station.
Recently  500 MW of capacity  came on line and it is  anticipated  that  another
500MW of new capacity may be available during 2006 as a result of the completion
of an in-City  generation  project  currently  under  construction.  We can not,
however,  be certain as to when the new power plant will be in  operation or the
nature of future New York City  energy,  capacity or ancillary  services  market
requirements or design.


                                       64
<PAGE>


KeySpan  continues  to believe that New York City  represents a strong  capacity
market and has entered into an International Swap Dealers  Association  ("ISDA")
Master  Agreement for a fixed for float  unforced  capacity  financial swap (the
"Swap  Agreement")  with Morgan Stanley  Capital Group Inc.  ("Morgan  Stanley")
dated as of January 18, 2006. The Swap Agreement has a three year term beginning
May 1, 2006,  (assuming a condition to effectiveness  has been satisfied by such
date). The notional quantity is 1,800,000kW (the "Notional Quantity") of In-City
Unforced Capacity and the fixed price is $7.57/kW-month ("Fixed Price"), subject
to adjustment upon the occurrence of certain events. Settlement would occur on a
monthly basis based on the In-City  Unforced  Capacity  price  determined by the
relevant New York  Independent  System Operator Spot Demand Curve Auction Market
("Floating  Price").  For each monthly  settlement  period, the price difference
will equal the Fixed Price minus the Floating Price. If such price difference is
less than zero,  Morgan  Stanley will pay KeySpan an amount equal to the product
of (a)  the  Notional  Quantity  and  (b)  the  absolute  value  of  such  price
difference.  Conversely,  if such price difference is greater than zero, KeySpan
will pay Morgan  Stanley  an amount  equal to the  product  of (a) the  Notional
Quantity and (b) the absolute value of such price  difference.

Energy Services

The Energy  Services  segment  includes  companies  that provide  energy-related
services to customers located  primarily within the Northeastern  United States.
Subsidiaries in this segment provide residential and small commercial  customers
with  service  and  maintenance  of energy  systems and  appliances,  as well as
operation  and  maintenance,  design,  engineering,  consulting  and fiber optic
services to commercial, institutional and industrial customers.

In  January  and  February  of 2005,  KeySpan  sold its  mechanical  contracting
subsidiaries in this segment and exited such  businesses.  In the fourth quarter
of  2004,  KeySpan's  investment  in  its  discontinued  mechanical  contracting
subsidiaries  was  written-down to an estimated fair value.  In 2005,  operating
losses  were  incurred  through  the  dates of sale of these  companies  of $4.1
million  after-tax,  including,  but not limited to, costs incurred for employee
related  benefits.  Partially  offsetting  these losses was an after-tax gain of
$2.3 million associated with the related divestitures, reflecting the difference
between the fair value  estimates  and the  financial  impact of the actual sale
transactions.  The net income  impact of the  operating  losses and the disposal
gain was a loss of $1.8 million,  or $0.01 per share in 2005. (See Note 2 to the
Consolidated  Financial Statements "Business Segments" for additional details on
the sale of the mechanical companies.)

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

--------------------------------------------------------------------------------
                                              Year Ended December 31,
(In Millions of Dollars)             2005              2004               2003
--------------------------------------------------------------------------------
Revenues                           $ 202.0           $ 193.9            $ 166.4
Less:  Operating expenses            204.7             227.8              199.4
       Goodwill impairment                              14.4                  -
--------------------------------------------------------------------------------
Operating  (Loss)                  $  (2.7)          $ (48.3)           $ (33.0)
--------------------------------------------------------------------------------


                                       65
<PAGE>


Operating Income 2005 vs 2004

The Energy Services  segment incurred an operating loss of $2.7 million in 2005,
compared  to a loss of $48.3  million  in  2004.  In 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. 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),  was  reflected  in
discontinued  operations.  (See Note 10 to the Consolidated Financial Statements
"Energy  Services -  Discontinued  Operations"  for  additional  details on this
charge.)

For 2005,  the  improved  performance  over last year,  excluding  the  goodwill
impairment  charge,  primarily  reflects a reduction in operating  expenses.  In
2004, charges associated with the write-off of accounts  receivable and contract
revenues on certain  projects  that were  determined to be  uncollectible,  were
incurred as well as the write-down of inventory balances.  Further, this segment
experienced   an  increase  in  gross  profit   margins  and   generally   lower
administrative costs in 2005.

Operating Income 2004 vs 2003

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,  in 2004  KeySpan  recorded  a  non-cash  goodwill
impairment  charge in  continuing  operations  of $14.4  million.  Excluding the
goodwill  impairment  charge,  operating  income  for the  twelve  months  ended
December 31, 2004,  was  essentially  the same as 2003, as higher  revenues were
offset by higher operating expenses.

Energy Investments

The Energy  Investments  segment  consists of our gas exploration and production
investments,  as well as  certain  other  domestic  energy-related  investments.
KeySpan's gas exploration  and production  activities  include its  wholly-owned
subsidiaries  Seneca  Upshur  Petroleum,  Inc.   ("Seneca-Upshur")  and  KeySpan
Exploration  and  Production,  LLC  ("KeySpan  Exploration").  Seneca-Upshur  is
engaged in gas exploration and production activities primarily in West Virginia.
KeySpan  Exploration  is  primarily  engaged  in a joint  venture  with  Houston
Exploration.

This segment is also  engaged in pipeline  development  activities.  KeySpan and
Duke Energy Corporation each own a 50% interest in 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.  Further,  KeySpan has a 21% interest in the  Millennium
Pipeline project which is expected to transport up to 525,000 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.  These subsidiaries are


                                       66
<PAGE>


accounted for under the equity method of accounting.  Accordingly, equity income
from these  investments  is reflected as a component of operating  income in the
Consolidated  Statement of Income.  KeySpan also owns a 600,000 barrel liquefied
natural gas ("LNG") storage and receiving facility in Providence,  Rhode Island,
through its wholly owned  subsidiary  KeySpan LNG, the  operations  of which are
fully  consolidated.  KeySpan LNG is re-evaluating  its plans to upgrade its LNG
facility in  Providence,  Rhode Island in light of the FERC decision that denied
KeySpan  LNG's  application  for FERC  authorization  to expand the  facility to
accept marine deliveries and triple vaporization capacity.

During the first quarter of 2004, we also had an  approximate  61% investment in
certain  midstream  natural gas assets in Western Canada through KeySpan Canada.
These assets included 14 processing plants and associated gathering systems that
produced  approximately  1.5 BCFe of natural gas daily and  provided  associated
natural gas liquids  fractionation.  These operations were fully consolidated in
KeySpan's  Consolidated  Financial  Statements.  On April 1, 2004,  KeySpan  and
KeySpan  Facilities  Income Fund (the "Fund"),  an open-ended income trust which
previously  owned a 39% interest in KeySpan  Canada,  consummated  a transaction
that  reduced  KeySpan's  ownership  interest  in  KeySpan  Canada  to 25%.  The
transaction  resulted in a gain of $22.8 million  ($10.1 million  after-tax,  or
$0.06 per share).  Effective  April 1, 2004  KeySpan  Canada's  earnings and our
ownership  interest in KeySpan Canada were accounted for on the equity method 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. (See Note 2 to the Consolidated
Financial  Statements  "Business Segments" for additional details regarding this
transaction.)

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.  Additionally,  we sold our 20%  interest in Taylor NGL LP
that  owned and  operated  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.

In the first  quarter of 2005,  KeySpan sold its 50% interest in Premier,  a gas
pipeline from southwest  Scotland to Northern  Ireland  pursuant to a Share Sale
and Purchase Agreement with BG Energy Holdings Limited and Premier  Transmission
Financing Public Limited Company  ("PTFPL"),  under which all of the outstanding


                                       67
<PAGE>


shares of Premier were to be purchased by PTFPL. On March 18, 2005, the sale was
completed and generated cash proceeds of $48.1 million. In the fourth quarter of
2004,  KeySpan  recorded a pre-tax non-cash  impairment  charge of $26.5 million
reflecting the difference between the anticipated cash proceeds from the sale of
Premier  compared to its carrying value. The final sale of Premier resulted in a
pre-tax gain of $4.1 million  reflecting the difference from earlier  estimates.
This gain was  recorded in other  income and  (deductions)  on the  Consolidated
Statement of Income.

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 and  operating  statistics  for  these  energy-related
investments  are set forth in the  following  table for the  periods  indicated.
These results exclude the results of Houston Exploration.
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                                 Year Ended December 31,
(In Millions of Dollars)                                2005               2004               2003
---------------------------------------------------------------------------------------------------
<S>                                                    <C>                <C>               <C>
Revenues                                              $ 43.0            $  58.9            $ 119.0
Less: Operation and maintenance expense                 26.5               33.5               68.6
          Ceiling test write-down                          -               48.2                  -
          Impairment charge                                -               26.5                  -
          Other operating expenses                      11.1               15.3               27.3
Add:  Equity earnings                                   15.1               25.8               19.1
          Sale of assets                                 0.1                5.0                  -
---------------------------------------------------------------------------------------------------
Operating Income (Loss)                               $ 20.6            $ (33.8)           $  42.2
---------------------------------------------------------------------------------------------------
</TABLE>
Operating income above reflects 100% of KeySpan Canada's results from January 1,
2003 through April 1, 2004.

Operating Income 2005 vs 2004

For the twelve months ended December 31, 2005, operating income for this segment
increased $54.4 million compared to the same period of 2004, reflecting non-cash
impairment  charges  recorded last year of $74.7 million.  As noted earlier,  in
2004,  KeySpan's wholly owned gas exploration and production  subsidiaries  that
have remained with KeySpan after the Houston Exploration transaction, recorded a
non-cash  impairment  charge of $48.2 million 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.)
Further,  in the fourth  quarter of 2004,  KeySpan  recorded a pre-tax  non-cash
impairment  charge  of $26.5  million  reflecting  the  difference  between  the
anticipated  cash  proceeds  from the sale of Premier  compared to its  carrying
value.

Operating  income for the twelve months ended  December 31, 2004,  also includes
$16.5  million  in  earnings  from  KeySpan  Canada.  The  remaining  activities
reflected a decrease in operating  income of $3.8 million  primarily  due to the
sale of real property in 2004.


                                       68
<PAGE>


Operating Income 2004 vs 2003

The decrease in comparative  operating  income in 2004 compared to 2003 of $76.0
million  reflects the impairment  charges recorded in 2004, as well as our lower
ownership  interest in KeySpan  Canada.  Operating  income for the twelve months
ended December 31, 2004,  includes $16.5 million in earnings from KeySpan Canada
compared  to  operating  income of $29.7  million  for the twelve  months  ended
December 31, 2003.  Excluding the  impairment  charges and KeySpan  Canada,  the
remaining  activities reflected an increase in operating income of $11.9 million
primarily  due to the sale of real  property in 2004,  higher  earnings from gas
pipeline investments and lower administrative costs.

During  the  first  five  months of 2004,  our gas  exploration  and  production
investments  also  included a 55% equity  interest in Houston  Exploration,  the
operations  of which  were  consolidated  in  KeySpan's  Consolidated  Financial
Statements.  On June 2, 2004,  KeySpan  exchanged  10.8 million shares of common
stock of Houston Exploration for 100% of the stock of Seneca-Upshur,  previously
a wholly owned subsidiary of Houston  Exploration.  This transaction reduced our
interest in Houston  Exploration  from 55% to the then  current  level of 23.5%.
Effective  June 2,  2004,  Houston  Exploration's  earnings  and  our  ownership
interest  in Houston  Exploration  were  accounted  for on the equity  method of
accounting. 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.   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.

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.




                                       69
<PAGE>


Selected financial data and operating statistics for Houston Exploration for
2004 and 2003 are set forth in the following table.

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

                                                      Year Ended December 31,
(In Millions of Dollars)                               2004             2003
------------------------------------------------------------------------------
Revenues                                             $ 268.1          $ 495.3
Depletion and amortization expense                     104.6            204.1
Other operating expenses                                45.7             94.9
Add: Equity Earnings                                    20.7                -
------------------------------------------------------------------------------
Operating Income                                     $ 138.5          $ 196.3
------------------------------------------------------------------------------

Houston Exploration

Operating Income 2004 vs 2003

The decline in  operating  income of $57.8  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 June 2, 2004,  then held an  approximate  23.5% interest
for the five month  period June 2, 2004 through  October 31, 2004.  KeySpan then
sold its remaining 23.5% interest in Houston Exploration in November 2004.

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 FERC and all necessary  permits from the
State of New York. The State of Connecticut denied Islander East's request for a
consistency  determination  under the Coastal Zone  Management  Act ("CZMA") and
application for a permit under Section 401 of the Clean Water Act. Islander East
appealed  the  State of  Connecticut's  determination  on the CZMA  issue to the
United  States  Department  of Commerce.  In 2004,  the  Department  of Commerce
overrode  Connecticut's  denial and  granted  the CZMA  authorization.  Islander
East's petition for a declaratory order overriding the denial of the Clean Water
Act permit is pending with  Connecticut's  State Superior  Court.  Pursuant to a
provision of the Energy Act,  Islander East has appealed the denial of the Clean
Water Act permit  directly to the United  States Court of Appeals for the Second
Circuit and has moved to stay the Connecticut  case pending the Second Circuit's
decision.  The  State  of  Connecticut  has  filed a  motion  to  challenge  the
constitutionality  of the  provisions  of the Energy Act  providing  this appeal
right.  The appeal was argued in January 2006 and a decision is expected  within
the first six months of 2006. Various options for the financing of this pipeline
construction  are being  evaluated.  As of December  31, 2005,  KeySpan's  total
capitalized costs associated with the siting and permitting of the Islander East
pipeline were approximately $24.6 million.


                                       70
<PAGE>


KeySpan also owns a 21% ownership  interest in the Millennium  Pipeline project.
KeySpan  acquired  its  interest in the project from Duke Energy in August 2004.
The other  partners in the  Millennium  Pipeline are  Columbia Gas  Transmission
Corp., a unit of NiSource  Incorporated  and DTE Energy.  It is anticipated that
KeySpan will acquire an additional  5.25% ownership  interest in Millennium from
Columbia during the first quarter of 2006, bringing our total ownership interest
in Millennium to 26.25%.  The  Millennium  Pipeline  project is  anticipated  to
transport  up to 525,000  DTH of natural gas a day from  Corning to Ramapo,  New
York,  interconnecting  with the pipeline  systems of various other utilities in
New York.  The project  received a FERC  certificate  to construct,  acquire and
operate the  facilities in 2002. On August 1, 2005, the project filed an amended
application with FERC requesting, among other things, approval of a reduction in
capacity and maximum allowable  operating pressure,  minor route  modifications,
the addition of certain  facilities and the  acquisition  of certain  facilities
from Columbia Gas Transmission Corporation.  Additionally, in December 2005, The
Consolidated  Edison Company of New York ("Con Edison"),  KEDLI and Columbia Gas
Transmission each entered into amended precedent agreements to purchase capacity
on the  pipeline.  KEDLI has  agreed to  purchase  150,000  DTH per day from the
Millennium  Pipeline system,  increasing to 200,000 DTH in the third year of the
pipeline  being in  service.  This will  provide  KEDLI with new,  competitively
priced supplies of natural gas from Canada.  Subject to, among other things, the
conditions  precedent  in the  precedent  agreements,  the receipt of  necessary
regulatory  approvals and financing,  it is anticipated that construction on the
Millennium  Pipeline  will be in service in either 2007 or 2008.  As of December
31, 2005,  total  capitalized  costs  associated  with the  Millennium  Pipeline
project were $10.4 million.

In 2005,  KeySpan LNG entered into a joint  development  agreement  with BG, LNG
Services,  a subsidiary  of British  Gas, to upgrade  KeySpan  LNG's  liquidfied
natural  gas  ("LNG")  facility  to  accept  marine  deliveries  and  to  triple
vaporization (or regasification) capacity. In June 2005, the FERC denied KeySpan
LNG's  application  to expand the  facility  citing  concerns  that the proposed
upgraded  facility would not meet current  federal safety  standards,  which the
facility is not currently  subject to. KeySpan sought a rehearing with FERC, and
on January 20, 2006 the FERC denied such  request,  although the order  provided
that KeySpan LNG could file an amendment to its original application  addressing
a  revised  expansion  project  which  would  differ   substantially  from  that
originally proposed by KeySpan. Any amendment  application would need to include
a detailed analysis of the new project scope, including upgrades to the existing
facilities  and  alternative  plans  for any  service  disruptions  that  may be
necessary during  construction of a new expanded project.  KeySpan is evaluating
whether to appeal FERC's current order.

In  addition  to the
proceeding  at FERC,  KeySpan  LNG also is involved  in seeking  other  required
regulatory  approvals and the  resolution of certain  litigation  regarding such
approvals.  In February  2005,  KeySpan LNG filed an action in Federal  District
Court in Rhode Island seeking a declaratory  judgment that it is not required to
obtain a "Category B Assent"  from the State of Rhode  Island and an  injunction
preventing the Rhode Island Coastal Resources  Management  Council ("CRMC") from
enforcing the Category B assent  requirements.  In March 2005,  the Rhode Island
Attorney  General  answered the complaint  and moved to substitute  the State of
Rhode Island as the  defendant  and filed a  counterclaim  seeking a declaratory
judgment that the expansion  requires a Category B Assent. In April, the parties
filed cross motions for summary judgment with respect to all issues presented to
the Court.  On April 14, 2005, the Attorney  General also filed on behalf of the
State a complaint  against  KeySpan LNG in Rhode  Island  State  Superior  Court
raising  substantially the same issues as the federal court action.  KeySpan LNG
removed  that  action to  federal  court and moved  for  summary  judgment.  The
Attorney General subsequently  withdrew both the motion to substitute defendants
and the counterclaim.  Although the Court had indicated its intention to issue a
decision in the pending cases by August 2005,  the Court has now indicated  that
it will stay the  litigation  pending  resolution of the FERC  rehearing  and/or
appeal process  discussed above.  Since the FERC order is a recent  development,
the Court has not yet taken any action.  As of December 31, 2005, our investment
in this project was $15.3 million.


                                       71
<PAGE>


Allocated Costs

As previously  noted,  at December 31, 2005 KeySpan was a holding  company under
PUHCA 1935. As a result of the Energy Act,  PUHCA 1935 was repealed and replaced
by PUHCA 2005 as of February 8, 2006. Under PUHCA 1935, the SEC had jurisdiction
over our holding company  activities,  including the regulation of our affiliate
transactions  and service  companies.  In accordance with those  regulations and
state regulatory  agencies'  regulations,  we established service companies that
provide:  (i) traditional  corporate and administrative  services;  (ii) gas and
electric  transmission and  distribution  system  planning,  marketing,  and gas
supply planning and procurement; and (iii) engineering and surveying services to
subsidiaries.  The SEC's  jurisdiction  over our holding company  activities was
eliminated  under PUHCA 2005,  although the SEC  continues to have  jurisdiction
over the  registration  and issuance of our securities under the securities law.
These service  companies are now subject to the  jurisdiction  of the FERC under
PUHCA 2005, as well as subject to regulations and orders of the NYPSC, MADTE and
NHPUC.  See  "Regulation  and Rate Matters" for  additional  information  on the
Energy Act.

The operating  income  variation as reflected in "elimination  and other" is due
primarily to costs residing at KeySpan's holding company level such as corporate
advertising  and strategic  review  costs.  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.

Operating income  variations in  "eliminations  and other" between 2004 and 2003
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, as noted, in 2004 KeySpan recorded an $11.6 million gain
from the  settlement  with its insurance  carriers  regarding  cost recovery for
expenses incurred at a non-utility  environmental  site. It should be noted that
in 2003 KeySpan recorded a $10 million  favorable  adjustment 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  decreased  $346.8  million,  or 46%,  for the twelve
months  ended  December  31, 2005  compared to 2004,  reflecting,  in part,  the
absence of Houston  Exploration  and KeySpan Canada which  combined  contributed
approximately  $230  million to  consolidated  operating  cash flow in 2004.  It
should  be  noted  that in  prior  years,  Houston  Exploration  funded  its gas
exploration and development  activities,  in part, from available cash flow from
operations.  In addition,  due to the significant increase in natural gas prices
in 2005,  KeySpan's gas distribution  utilities paid  approximately $215 million
more in 2005  compared to 2004 for the purchase of natural gas that is currently
in inventory. As noted previously, 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.  Further in 2005 the Internal Revenue Service
("IRS")  published new  regulations  related to the  capitalization  of costs of
self-constructed  property  for  income  tax  purposes.  As a  result  of  these


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<PAGE>


regulations,  KeySpan  incurred  approximately  $60 million in higher income tax
payments  for the twelve  months ended  December  31, 2005  compared to the same
period  in 2004.  These  adverse  impacts  to cash  flow  from  operations  were
partially offset by lower interest payments and higher core earnings.

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.

At December 31,  2005,  we had cash and  temporary  cash  investments  of $124.5
million.  During the twelve  months ended  December 31, 2005,  we repaid  $254.6
million  of  commercial  paper  and,  at  December  31,  2005,  $658  million of
commercial paper was outstanding at a weighted-average  annualized interest rate
of 4.38%.  At  December  31,  2005,  KeySpan  had the  ability to issue up to an
additional $842 million of short-term debt under its commercial paper program.

In June 2005,  KeySpan closed on a $920 million  revolving  credit  facility for
five years due June 24, 2010,  which was syndicated  among fifteen banks, and an
amended  $580  million  revolving  credit  facility  due  June 24,  2009.  These
facilities replaced an existing $660 million, 3-year facility due June 2006, and
a 5-year $640 million facility due June 2009. The two credit  facilities,  which
now total $1.5  billion - $920  million for five years  through  2010,  and $580
million  for the  amended  facility  through  2009,  will  continue  to  support
KeySpan's commercial paper program for ongoing working capital needs.

The fees for the  facilities  are based on KeySpan's  current credit ratings and
are increased or decreased  based on a downgrading  or upgrading of our ratings.
The current  annual  facility  fee is 0.07% based on our credit  rating of A3 by
Moody's  Investor  Services and A by Standard & Poor's for each  facility.  Both
credit  facilities allow for KeySpan to borrow using several  different types of
loans;  specifically,  Eurodollar  loans, ABR loans, or competitively bid loans.
Eurodollar  loans are based on the Eurodollar rate plus a margin that is tied to
our applicable  credit  ratings.  ABR loans are based on the higher 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 utility 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 65% as at the


                                       73
<PAGE>


last day of any fiscal quarter. Violation of these covenants 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.  At
December  31,  2005,  KeySpan's  consolidated  indebtedness  was  50.7%  of  its
consolidated capitalization and KeySpan was in compliance with all covenants.

Subject to certain conditions set forth in the credit facility,  KeySpan has the
right, at any time, to increase the commitments  under the $920 million facility
up to an additional $300 million. In addition,  KeySpan has the right to request
that the termination date be extended for an additional period of 365 days prior
to each  anniversary  of the  closing  date.  This  extension  option,  however,
requires the approval of lenders holding more than 50% of the total  commitments
to such  extension  request.  Under the  agreements,  KeySpan has the ability to
replace  non-consenting  lenders  with  other  pre-approved  banks or  financial
institutions.  Upon  effectiveness  of PUHCA  2005,  KeySpan's  ability to issue
commercial  paper is no  longer  limited  by the SEC.  Accordingly,  subject  to
compliance with the foregoing conditions,  KeySpan is currently able to issue up
to $1.5 billion of commercial paper.

A substantial  portion of consolidated  revenues are derived from the operations
of businesses within the Electric  Services segment,  that are largely dependent
upon two large customers - LIPA and the NYISO.  Accordingly,  our cash flows are
dependent upon the timely payment of amounts owed to us by these counterparties.
(See the discussion under the caption "Electric  Services - LIPA Agreements" for
information  regarding the recent settlement  between KeySpan and LIPA regarding
the current contractual agreements.)

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 Millions of Dollars)                         2005               2004
--------------------------------------------------------------------------
Gas Distribution                               $ 410.3            $ 414.5
Electric Services                                 88.8              150.3
Energy Investments                                23.6              160.2
Energy Services and other                         16.8               25.3
--------------------------------------------------------------------------
                                               $ 539.5            $ 750.3
--------------------------------------------------------------------------

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 costs to
maintain  our  generating  facilities  and,  for  2004,  expand  the  Ravenswood


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<PAGE>


Generating Station.  Construction expenditures related to the Energy Investments
segment for 2004 primarily  reflect costs  associated  with gas  exploration and
production  activities  of  Houston  Exploration,  as well as costs  related  to
KeySpan Canada's gas processing facilities.

Construction  expenditures  for  2006 are  estimated  to be  approximately  $630
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 January 2006, the NYPSC issued orders granting additional financing authority
to KEDNY and KEDLI. KEDNY has the authority, through December 31, 2008, to issue
up to $475 million of new  securities and to refinance up to $650 million of its
existing debt obligations.  KEDLI has the authority,  through December 31, 2008,
to  issue up to $450  million  of new  securities  and to  refinance  up to $525
million of its existing  debt  obligations.  KEDNY and KEDLI had sought a waiver
from the  requirement in the existing rate plans that KEDNY and KEDLI must raise
their own long-term debt or preferred  stock and may not derive such  securities
from KeySpan. The NYPSC declined to grant the requested waiver.

In December 2005, KEDNY converted $50 million of fixed rate Gas Facility Revenue
Bonds  ("GFRB")  (5.64% GFRB Series D1 and D2 due 2026) into variable rate debt.
The interest rate on these bonds is now reset, through an auction process, every
seven days.

In November 2005, KEDNY,  issued $137 million of tax-exempt GFRB through the New
York  State  Energy  Research  and  Development  Authority  ("NYSERDA")  in  the
following  series:  (i) $82 million of 4.70% GFRB,  2005 Series A (the "Series A
Bonds");  and (ii) $55 million GFRB,  2005 Series B (the "Series B Bonds").  The
interest rate on the Series B bonds is reset every seven days through an auction
process.  KEDNY used the  proceeds  from this  issuance to redeem the  following
three series:  (i) $41 million  Adjustable  Rate GFRB Series 1989 A due February
2024; (ii) $41 million Adjustable Rate GFRB Series 1989 B due February 2024; and
(iii) $55 million  5.60% GFRB Series 1993 C due June 2025.  KEDNY  incurred $3.7
million in call premiums and financing fees, all of which have been deferred for
future rate recovery.

In January 2005, KeySpan redeemed $500 million of outstanding debt - 6.15% notes
due 2006.  KeySpan  incurred  $20.9 million in call premiums and wrote-off  $1.3
million of previously  deferred costs.  Further, we accelerated the amortization
of approximately  $11.2 million of previously  unamortized  benefits  associated
with an interest rate swap on these bonds. The accelerated amortization, as well
as the write-off of previously  deferred costs was recorded to interest expense.
In addition,  during the first quarter of 2005,  $15 million of 8.87% notes of a
KeySpan subsidiary were redeemed at maturity.

Further,  $55.3  million of 7.07%  Series B preferred  stock was redeemed in May
2005 on its scheduled redemption date.  Additionally,  also in May 2005, KeySpan
called for  optional  redemption  $19.7  million of 7.17%  Series C of preferred
stock due 2008. KeySpan no longer has preferred stock outstanding.

In May 2002,  KeySpan issued 9.2 million MEDS Equity Units which were subject to
conversion to common stock upon  execution of the  three-year  forward  purchase
contract.  In 2005,  KeySpan was required to remarket the note  component of the
Equity Units between February 2005 and May 2005 and reset the interest


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<PAGE>


rate to the then current  market rate of interest;  however,  the reset interest
rate could not be set below 4.9%.  In March 2005,  KeySpan  remarketed  the note
component of $394.9  million of the Equity Units at the reset  interest  rate of
4.9% through their  maturity  date of May 2008.  The balance of the notes ($65.1
million) were held by the original  MEDS Equity Unit holders in accordance  with
their terms and not  remarketed.  KeySpan  then  exchanged  $300  million of the
remarketed  notes for $307.2  million of new 30 year notes  bearing an  interest
rate of 5.8%. Therefore,  KeySpan now has $160 million of 4.9% notes outstanding
with a maturity  date of May 2008 and $307.2  million of 5.8% notes  outstanding
with a maturity date of April 2035.

On May 16, 2005,  KeySpan  issued 12.1  million  shares of common  stock,  at an
issuance price of $37.93 per share pursuant to the terms of the forward purchase
contract.  KeySpan  received  proceeds of  approximately  $460  million from the
equity  issuance.  The number of shares  issued  was  dependent  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.

The following table represents the ratings of our long-term debt at December 31,
2005. 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.  Further  in the second  quarter of 2005,  Fitch  Ratings  revised  its
ratings on KeySpan's and its  subsidiaries'  long-term debt to positive outlook.
Moody's Investor Services,  however,  continues to maintain its negative outlook
ratings on KeySpan's and its subsidiaries' long-term debt.

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

Off-Balance Sheet Arrangements

Guarantees

KeySpan had a number of financial  guarantees with its  subsidiaries at December
31, 2005. KeySpan has 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  $385  million  sale/leaseback
transaction for the Ravenswood  Expansion including future decommission costs of
$19 million;  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 obligation is not recorded on the Consolidated
Balance  Sheet.  Further,  KeySpan has  guaranteed:  (i) up to $76.0  million of
surety bonds  associated  with certain  construction  projects  currently  being


                                       76
<PAGE>


performed by current and former  subsidiaries;  (ii) certain  supply  contracts,
margin  accounts and purchase  orders for certain  subsidiaries  in an aggregate
amount of $83.2  million;  and (iii)  $73.0  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 for these projects.  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 10 "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 and Commercial  Paper."  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."
The  table  below  reflects   maturity   schedules  for  KeySpan's   contractual
obligations  at December 31, 2005.  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 Millions of Dollars)
 Contractual Obligations                 Total         1 - 3 Years     4 - 5 Years     After 5 Years
----------------------------------------------------------------------------------------------------
<S>                                     <C>             <C>             <C>                <C>
 Long-term Debt                        $ 3,934.7       $   317.0       $ 1,522.3          $ 2,095.4
 Capital Leases                             10.8             3.2             2.5                5.1
 Operating Leases                          585.7           213.6           137.5              234.6
 Master Lease Payments                      99.7            85.5            14.2                  -
 Sale/Leaseback Arrangement                569.5            73.0            78.8              417.7
 Interest Payments                       2,873.6           663.7           380.0            1,829.9
 Demand Charges                            492.7           492.7               -                  -
----------------------------------------------------------------------------------------------------
 Total Contractual
     Cash Obligations                  $ 8,566.7       $ 1,848.7       $ 2,135.3          $ 4,582.7
----------------------------------------------------------------------------------------------------
 Commercial Paper                      $   657.6       Revolving
----------------------------------------------------------------------------------------------------
</TABLE>

For information regarding projected postretirement contributions,  see Note 4 to
the Consolidated Financial Statements "Postretirement Benefits." For information
regarding asset retirement obligations, see Note 7 to the Consolidated Financial
Statements "Contractual Obligations, Financial Guarantees and Contingencies."


                                       77
<PAGE>


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.

KeySpan  continually  evaluates  its critical  accounting  policies.  Based upon
current  facts and  circumstances  KeySpan has decided that  certain  accounting
policies that were  considered  "critical" at December 31, 2004 should no longer
be considered as critical accounting policies.  The accounting policies that are
no longer  considered  critical  are as  follows:  (i)  Percentage-of-completion
accounting is a method of accounting for long-term  construction  type contracts
in accordance with generally  accepted  accounting  principles.  This accounting
policy was used for engineering and mechanical  contracting  revenue recognition
by the Energy Services segment.  However,  since KeySpan has sold its mechanical
contracting  subsidiaries,  contracting  revenue  recognition  is  no  longer  a
significant  accounting  issue; and (ii) The full cost accounting method is used
by our gas exploration and production  subsidiaries to account for their natural
gas and oil properties.  Seneca-Upshur and KeySpan Exploration continue to apply
this  accounting  treatment.  However,  since  KeySpan  has sold  its  ownership
interest  in Houston  Exploration,  KeySpan's  gas  exploration  and  production
activities are not a significant  aspect of its overall business  operations and
therefore, full cost accounting is no longer a significant accounting policy.

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.  The assumptions  used to
measure  the fair value of our  investments  are the same as those used by us to
prepare  annual  operating  segment  and  consolidated  earnings  and cash  flow
forecasts.  In  addition,  these  assumptions  are used to set annual  budgetary
guidelines.

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.  At December 31, 2005,  KeySpan had $1.7 billion of recorded  goodwill
and has concluded  that the fair value of the business  units that have recorded
goodwill exceed their carrying value.


                                       78
<PAGE>


As noted  previously,  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.
(See   Note   10   to   the   Consolidated    Financial    Statements    "Energy
Services-Discontinued Operations" for further details.)

Also as noted previously,  at the end of 2004, KeySpan  anticipated  selling its
then 50% interest in Premier. This investment was 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 reflected the
difference  between  the  anticipated  cash  proceeds  from the sale of  Premier
compared to its  carrying  value at that time 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  and
EnergyNorth)  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  orders issued by the MADTE  relating to the  acquisition by Eastern
Enterprises  of  Colonial  Gas and Essex Gas,  the base  rates  charged by these
companies have been frozen at their current levels for a ten-year  period ending
2009.  Due to the length of these base rate freezes,  Colonial Gas and Essex Gas
had previously  discontinued the application of SFAS 71.  EnergyNorth base rates
continue as set by the NHPUC in 1993.

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, 2005 could  result in a charge to net income of  approximately


                                       79
<PAGE>


$308.0 million or $1.81 per share, which would be classified as an extraordinary
item. In management's  opinion,  our regulated  subsidiaries  that currently are
subject to the  provisions of SFAS 71 will continue to be subject to SFAS 71 for
the foreseeable future.

As is further  discussed  under the caption  "Regulation  and Rate  Matters," in
October  2003 the MADTE  rendered  its decision on the Boston Gas 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  and the
rates established in those plans remain in effect. 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.

Management  believes  that  currently  available  facts  support  the  continued
application  of SFAS 71 and that  all  regulatory  assets  and  liabilities  are
recoverable or refundable in the current 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 2005,  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%.


                                       80
<PAGE>


KeySpan's master trust investment allocation policy target is 70% equity and 30%
fixed income. At December 31, 2005, 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 2005 expense by approximately $6 million, before
deferrals.

The year-end  December 31, 2005 weighted average discount rate used to determine
postretirement obligations was 5.75%. Our discount rate assumption was developed
by matching our plans' cash flows to the Citigroup  above-median  discount curve
spot rates.  The resulting yield is then rounded to the nearest 25 basis points.
A 25 basis point increase or decrease in the weighted average year-end  discount
rate  would  have had no  impact  on 2005  expense.  However,  a 25 basis  point
decrease in the  weighted  average  year-end  discount  rate would result in the
recording of an additional minimum pension  liability.  A year-end discount rate
of  5.5%  would  have  required  an  additional   $42  million  debit  to  other
comprehensive  income ("OCI") before taxes and  deferrals.  A year-end  discount
rate of 5.25%  would have  required an  additional  $338  million  charge to OCI
before taxes and deferrals.

At January 1, 2005, the weighted average discount rate used to determine pension
and  postretirement  obligations was 6.0%. A 25 basis point increase or decrease
in the weighted  average  discount  rate at the beginning of the year would have
impacted 2005 expense by approximately $15 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, 2005, 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 2005.  However,  although we have presently  exceeded
ERISA  funding  requirements,  our pension  plans,  on an actuarial  basis,  are
currently underfunded.  Therefore,  during 2005 KeySpan contributed $174 million
to its funded and unfunded postretirement plans.

For 2006, 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.


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Dividends

In the fourth  quarter of 2005 KeySpan  increased its dividend to an annual rate
of $1.86 per common share  beginning  with the quarterly  dividend to be paid in
February  2006.  Our  dividend  framework  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 $1.86 level.

Pursuant to NYPSC  orders,  the ability of KEDNY and KEDLI to pay  dividends  to
KeySpan is conditioned upon maintenance of a utility capital structure with debt
not exceeding 55% and 58%,  respectively,  of total utility  capitalization.  In
addition,  the level of dividends  paid by both  utilities  may not be increased
from current  levels if a 40 basis point penalty is incurred  under the customer
service performance  program. At the end of KEDNY's and KEDLI's most recent rate
years (September 30, 2005 and November 30, 2005, respectively), each company was
in  compliance  with  the  utility  capital  structure  required  by the  NYPSC.
Additionally, we have met the requisite customer service performance standards.

Regulation and Rate Matters

Gas Distribution

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 a 13.25% return on
equity), remain in effect until changed by the NYPSC. Under the agreement, 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 a 13.25%  return  on  equity  (other  than any  earnings  associated  with
discrete  incentives)  and 50% of any  utility  earnings  in excess of 100 basis
points above such threshold  level.  KEDNY did not earn above a 13.25% return on
equity in its rate year ended September 30, 2005.

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.  Under  the  agreement,  KEDLI is  subject  to an  earnings  sharing
provision  pursuant to which it is required to credit to firm  customers  60% of
any utility earnings for any rate year ended November 30, 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 an11.10% return on equity
in its rate year ended November 30, 2005.

At this time, we are evaluating  various  options  regarding the KEDNY and KEDLI
rate  plans,  including  but not limited to,  proposing  new rate plans.  In the
meantime,  KeySpan  filed a joint  petition  for KEDNY and KEDLI  with the NYPSC
seeking  authority  to defer  certain  costs  associated  with  high gas  costs.
Specifically,  KeySpan  seeks  authority to defer the following  costs,  each of
which is directly  linked to increased gas prices:  (i) the portion of increased



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bad debt expense attributable to increased gas cost; (ii) the return requirement
on the increased cost of gas in storage; and (iii) the return requirement on the
increased need for working capital. KeySpan projects total combined deferrals of
approximately  $67 million and $65  million in 2006 and 2007,  respectively.  On
January 25,  2006,  the NYPSC  noticed the joint  petition in the New York State
Register.

Boston Gas, Colonial Gas and Essex Gas 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.

Effective  November 1, 2003, the MADTE approved a $25.9 million increase in base
revenues for Boston Gas 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 November 1, 2005, the MADTE approved a base rate
increase  of $7.2  million  under the Plan.  In  addition,  an  increase of $7.5
million in the local  distribution  adjustment  clause was  approved  to recover
pension  and other  postretirement  costs.  The MADTE  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's weighted-average cost
of capital.

In connection with the Eastern Enterprises  acquisition of Colonial Gas in 1999,
the MADTE  approved a merger and rate plan that resulted in a ten year freeze of
base rates to  Colonial  Gas'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  discontinued  its  application  of SFAS 71.
Essex Gas is also under a ten-year  base rate  freeze and has also  discontinued
its application of SFAS 71.

In  December  2005,  Boston Gas  received a MADTE  order  permitting  regulatory
recovery  of the 2004  gas  cost  component  of bad  debt  write-offs.  This was
approved for full recovery as an exogenous cost  effective  November 1, 2005. In
addition,  effective  January 1, 2006,  Boston Gas is permitted to fully recover
the gas cost component of bad debt write-offs through its cost-of-gas adjustment
clause rather than filing for recovery as an exogenous  cost. We have  reflected
both of these favorable  recovery  mechanisms in our December 31, 2005 Allowance
for Doubtful Accounts reserve  requirement and related expense.  Boston Gas also
plans  to  request  full  recovery,  as an  exogenous  cost,  the  2005 gas cost
component of bad debt write-offs from Boston Gas ratepayers  beginning  November
1, 2006.

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


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under rates approved by the FERC in accordance with the PSA entered into between
KeySpan and LIPA in 1998.  The original 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 to reset rates effective
January 1, 2004.  Under the new  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.  (See Electric  Services - "LIPA  Agreements"
for a discussion of the 2006  settlement  between KeySpan and LIPA regarding the
current contractual agreements.)

The Energy  Policy Act of 2005 and the Public  Utility  Holding  Company Acts of
1935 and 2005

At December 31, 2005,  KeySpan and certain of its  subsidiaries  were subject to
the  jurisdiction of the SEC under PUHCA 1935. The rules and  regulations  under
PUHCA 1935,  generally  limited the operations of a holding  company to a single
integrated public utility system, plus additional energy-related  businesses. In
addition,  the  principal  regulatory  provisions  of PUHCA 1935:  (i) regulated
certain transactions among affiliates within a holding company system, including
the  payment  of  dividends  by such  subsidiaries  to a holding  company;  (ii)
governed the issuance, acquisition and disposition of securities and assets by a
holding  company and its  subsidiaries;  (iii)  limited the entry by  registered
holding  companies and their  subsidiaries  into businesses  other than electric
and/or gas  utility  businesses;  and (iv)  required  SEC  approval  for certain
utility mergers and acquisitions.

In August  2005,  the Energy Act was enacted by Congress  and signed into law by
the  President.  The  Energy Act is a broad  based  energy  bill that  places an
increased  emphasis on the production of energy and promotes the  development of
new  technologies  and  alternative  energy  sources by providing tax credits to
companies that produce natural gas, oil, coal, electricity and renewable energy.
For KeySpan,  one of the more  significant  provisions of the Energy Act was the
repeal of PUHCA 1935,  effective  February 8, 2006,  and the transfer of certain
holding company oversight from the SEC to FERC pursuant to PUHCA 2005.

Pursuant  to PUHCA  2005,  the SEC no longer has  jurisdiction  over our holding
company  activities,   other  than  those  traditionally   associated  with  the
registration and issuance of our securities  under the federal  securities laws.
FERC now has  jurisdiction  over  certain  of our  holding  company  activities,
including (i) regulating  certain  transactions  among our affiliates within our
holding company system; (ii) governing the issuance, acquisition and disposition
of  securities  and assets by certain of our public  utility  subsidiaries;  and
(iii) approving certain utility mergers and acquisitions.

Moreover,  our affiliate transactions also remain subject to certain regulations
of the NYPSC, MADTE and NHPUC, in addition to FERC.

Electric Services - 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,  KeySpan and LIPA entered into three
major  long-term  service  agreements  that (i)  provide to LIPA all  operation,


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maintenance and construction  services and significant  administrative  services
relating to the Long  Island  electric  transmission  and  distribution  ("T&D")
system  pursuant to the Management  Services  Agreement  (the "1998 MSA");  (ii)
supply LIPA with electric generating  capacity,  energy conversion and ancillary
services  from our Long Island  generating  units  pursuant to the Power  Supply
Agreement  (the "1998  PSA") and other  long-term  agreements  through  which we
provide LIPA with  approximately  one half 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 the Energy  Management  Agreement (the "1998 EMA").
We also purchase energy,  capacity and ancillary  services in the open market on
LIPA's behalf under the 1998 EMA. The 1998 MSA, 1998 PSA and 1998 EMA all became
effective  on May 28,  1998 and are  collectively  referred  to as the 1998 LIPA
Agreements.

On February 1, 2006,  KeySpan and LIPA  entered into (i) an amended and restated
Management  Services Agreement (the "2006 MSA"),  pursuant to which KeySpan will
continue to operate and  maintain  the electric T&D System owned by LIPA on Long
Island;  (ii) a new Option and  Purchase  and Sale  Agreement  (the "2006 Option
Agreement"),  to replace the Generation  Purchase Rights  Agreement (as amended,
the "GPRA"),  pursuant to which LIPA had the option,  through December 15, 2005,
to acquire  substantially  all of the electric  generating  facilities  owned by
KeySpan on Long Island;  and (iii) a Settlement  Agreement (the "2006 Settlement
Agreement")  resolving outstanding issues between the parties regarding the LIPA
Agreements.  The 2006 MSA,  the 2006 Option  Agreement  and the 2006  Settlement
Agreement  are  collectively  referred to herein as the "2006 LIPA  Agreements".
Each of the 2006 Agreements will become effective as of January 1, 2006 upon all
of the 2006 LIPA  Agreements  receiving  the  required  governmental  approvals;
otherwise none of the 2006 LIPA Agreements will become effective.

2006 Settlement Agreement

Pursuant to the terms of the 2006 Settlement Agreement,  KeySpan and LIPA agreed
to resolve issues that have existed between the parties  relating to the various
1998 LIPA Agreements. In addition to the resolution of these matters,  KeySpan's
entitlement  to utilize  LILCO's  available tax credits and other tax attributes
will  increase from  approximately  $50 million to  approximately  $200 million.
These  credits  and  attributes  may be used  to  satisfy  KeySpan's  previously
incurred indemnity  obligation to LIPA for any federal income tax liability that
may result from the settlement of a pending  Internal  Revenue Service audit for
LILCO's tax year ended March 31, 1999. In recognition of these items, as well as
for the  modification  and extension of the 1998 MSA and the  elimination of the
GPRA,  upon  effectiveness  of the  Settlement  Agreement  KeySpan will record a
contractual  asset  in the  amount  of  approximately  $160  million,  of  which
approximately  $110  million  will be  attributed  to the right to utilize  such
additional  credits  and  attributes  and  approximately  $50  million  will  be
amortized over the eight year term of the 2006 MSA. In order to compensate  LIPA
for the  foregoing,  KeySpan  will pay LIPA $69  million in cash and will settle
certain accounts  receivable in the amount of approximately $90 million due from
LIPA.

Generation Purchase Rights Agreement and 2006 Option Agreement.

Under an amended GPRA,  LIPA had the right to acquire  certain of KeySpan's Long
Island-based  generating assets formerly owned by LILCO, at fair market value at
the time of the exercise of such right.  LIPA was  initially  required to make a
determination  by May 2005,  but  KeySpan  and LIPA agreed to extend the date by


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which LIPA was to make this  determination  to December 15, 2005. As part of the
2006  settlement  between  KeySpan and LIPA,  the parties  entered into the 2006
Option  Agreement  whereby LIPA has the option during the period January 1, 2006
to December 31, 2006 to purchase only KeySpan's Far Rockaway and/or E.F. Barrett
Generating  Stations  (and certain  related  assets) at a price equal to the net
book value of each facility.  The 2006 Option  Agreement  replaces the GPRA, the
expiration  of which  has been  stayed  pending  effectiveness  of the 2006 LIPA
Agreements.  In the event such  agreements do not become  effective by reason of
failure  to  secure  the  requisite  governmental  approvals,  the GPRA  will be
reinstated  for a period of 90 days.  If LIPA were to  exercise  the  option and
purchase  one or both of the  generation  facilities  (i) LIPA and KeySpan  will
enter into an operation  and  maintenance  agreement,  pursuant to which KeySpan
will continue to operate  these  facilities,  through May 28, 2013,  for a fixed
management fee plus  reimbursement  for certain costs; and (ii) the 1998 PSA and
1998 EMA will be amended to reflect  that the  purchased  generating  facilities
would no longer be covered by those agreements.  It is anticipated that the fees
received  pursuant to the operation and  maintenance  agreement  will offset the
reduction in the operation and  maintenance  expense  recovery  component of the
1998 PSA and the reduction in fees under the 1998 EMA.

Management Services Agreements

Pursuant to the 1998 MSA, KeySpan manages the day-to-day operations, maintenance
and capital  improvements  of the T&D system.  LIPA  exercises  control over the
performance of the T&D system through  specific  standards for  performance  and
incentives.  In exchange for providing the services, the 1998 MSA provides for a
$10 million annual  management fee and provides  certain  incentives and imposes
certain penalties based upon performance.  We earn certain incentives for budget
under runs  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 under runs, and (ii) retain 50% of
additional annual under runs up to 15% of the total cost budget,  thereafter all
savings accrue to LIPA.  With respect to cost overruns,  we 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.  During 2005, we
performed our  obligations  under the 1998 MSA within the agreed upon budget and
we earned $7.4 million in non-cost performance incentives.

When  originally  executed the 1998 MSA had a term  expiring on May 28, 2006. In
2002,  in  connection  with an  extension  of the  GPRA  term,  the 1998 MSA was
extended for 31 months through 2008. As a result of the recent  negotiations and
settlement  between KeySpan and LIPA discussed  above,  the parties entered into
the 2006 MSA.

In place of the previous compensation  structure (whereby KeySpan was reimbursed
for budgeted  costs,  and earned a management  fee and certain  performance  and
cost-based incentives), KeySpan's compensation for managing the T&D System under
the 2006 MSA consists of two  components:  a minimum  compensation  component of
$224 million per year and a variable component based on electric sales. The $224
million  component  will  remain  unchanged  for three  years and then  increase
annually by 1.7%, plus inflation. The variable component, which will comprise no
more than 20% of  KeySpan's  compensation,  is based on  electric  sales on Long
Island  exceeding a base amount of 16,558 gigawatt hours,  increasing by 1.7% in
each year. Above that level,  KeySpan will receive  approximately 1.34 cents per


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kilowatt hour for the first contract  year,  1.29 cents per kilowatt hour in the
second  contract  year  (plus an annual  inflation  adjustment),  1.24 cents per
kilowatt hour in the third contract year (plus an annual inflation  adjustment),
with the per  kilowatt  hour rate  thereafter  adjusted  annually by  inflation.
Subject to certain  limitations,  KeySpan will be able to retain all operational
efficiencies realized during the term of the 2006 MSA.

LIPA will  continue to reimburse  KeySpan for certain  expenditures  incurred in
connection  with the  operation  and  maintenance  of the T&D System,  and other
payments made on behalf of LIPA,  including:  real property and other T&D System
taxes, return postage, capital construction expenditures and storm costs.

The 2006 MSA  provides for a number of  performance  metrics  measuring  various
aspects of KeySpan's  performance in the operations and customer  service areas.
Poor  performance  in any metric may  subject  KeySpan  to  financial  and other
non-cost  penalties  (such  financial  penalties not to exceed $7 million in the
aggregate for all performance metrics in any contract year).  Subject to certain
limitations,  superior  performance  in  certain  metrics  can be used to offset
underperformance  in  other  metrics.   Consistent  failure  to  meet  threshold
performance levels for two metrics,  System Average Interruption  Duration Index
(two out of three  consecutive  years) and  Customer  Satisfaction  Index (three
consecutive years), will constitute an event of default under the 2006 MSA.

Should LIPA sell the T&D System to a private  entity during the term of the 2006
MSA,  LIPA shall have the right to terminate  the 2006 MSA,  provided  that LIPA
will be required to pay KeySpan's reasonable  transition costs and a termination
fee of (a) $28 million if the termination  date occurs on or before December 31,
2009,  and (b) $20 million if the  termination  date occurs  after  December 31,
2009.

Power Supply Agreements

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.  Since  October 1, 2004,  pursuant to a FERC
approved settlement,  the 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 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 1998
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 2005, we earned $4 million in incentives under this agreement.


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The 1998 PSA has a term of fifteen years through May 2013,  with LIPA having the
option to renew the 1998 PSA for an additional  fifteen year term.  The 1998 PSA
will be terminated  in the event that the GPRA is renewed and LIPA  purchases at
fair market value certain of KeySpan's Long Island based  generating  units.  If
the 2006 LIPA Agreements receive the requisite governmental approvals and become
effective,  and if LIPA exercises its rights under the 2006 Option  Agreement to
purchase  the two  generating  plants,  then LIPA and KeySpan will enter into an
operation and maintenance agreement,  pursuant to which KeySpan will continue to
operate these  facilities  for a fixed  management  fee plus  reimbursement  for
certain  costs;  and the 1998 PSA will be amended to reflect that the  purchased
generating  facilities  would  no  longer  be  covered  by the 1998  PSA.  It is
anticipated  that the fees received  pursuant to the  operation and  maintenance
agreement  will offset the reduction in the operation  and  maintenance  expense
recovery component of the 1998 PSA.

Energy Management Agreement

The 1998 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 1998 EMA provides  incentives  and
penalties  that can total $5 million  annually for  performance  related to fuel
purchases and off-system power  purchases.  In 2005, we earned EMA incentives in
an aggregate of $5 million.

The original term for the fuel supply service is fifteen years, expiring May 28,
2013,  and the original term for the  off-system  purchases  and sales  services
described is eight years,  expiring May 28, 2006.  In March 2005,  LIPA issued a
RFP for system power supply management  services beginning May 29, 2006 and fuel
management  services  for  certain of its  peaking  generating  units  beginning
January 1, 2006.  KeySpan submitted a bid in response to this RFP in April 2005.
LIPA has not yet selected a service provider.

In the event LIPA exercises its rights under the 2006 Option Agreement,  KeySpan
and LIPA  will  enter  into an  amendment  to the 1998 EMA  reflecting  that the
facilities  that LIPA  acquires  pursuant to the Option  Agreement are no longer
covered  under the 1998 EMA and as noted  above,  an operation  and  maintenance
agreement,   whereby  KeySpan  will  continue  to  operate  the  newly  acquired
facilities for a fixed management fee plus  reimbursement  for certain costs. It
is anticipated that the fees received  pursuant to the operation and maintenance
agreement  will offset the  reduction in any fees earned by KeySpan  pursuant to
the 1998 EMA.

Under the 1998 LIPA Agreements and the 2006 LIPA 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.

Power Purchase Agreements

KeySpan-Glenwood Energy Center, LLC and KeySpan-Port Jefferson Energy Center LLC
each have 25 year power purchase agreements with LIPA expring in 2027 (the "2002
LIPA  PPAs").  Under the terms of the 2002 LIPA PPAs,  these  subsidiaries  sell
capacity,  energy conversion services and ancillary services to LIPA. Each plant


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is designed  to produce  79.9 MW.  Pursuant  to the 2002 LIPA 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.

Ravenswood Generating Station

We currently sell capacity,  energy and ancillary  services  associated with the
Ravenswood  Generating  Station  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  Generating  Station to load
serving  entities,  i.e.  entities  that sell to  end-users  or to  brokers  and
marketers.

Other Contingencies

LIPA  completed  its  strategic  review  initiative  that it had  undertaken  in
connection  with among other reasons,  its option under the GPRA. As part of its
review,  LIPA engaged a team of advisors and  consultants,  held public hearings
and  explored  its  strategic   options,   including   continuing  its  existing
operations,  municipalizing,  privatizing,  selling  some,  but  not  all of its
assets,  becoming a regulator of rates and services, or merging with one or more
utilities.  Upon  completion of its strategic  review,  LIPA  determined that it
would continue its existing  operations,  as part of its settlement with KeySpan
and the negotiation of the 2006 LIPA Agreements.  As previously  noted, the 2006
LIPA Agreements are subject to governmental approvals,  and if such governmental
approvals are not received and the 2006 LIPA Agreements do not become effective,
then LIPA may revisit its strategic review alternatives.

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,  MADTE 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.

During 2005, KeySpan undertook an extensive review of all its current and former
properties that are or may be subject to environmental cleanup activities.  As a
result of this study, we adjusted  reserve  balances for estimated  manufactured
gas plant ("MGP")  related  environmental  cleanup  activities.  As noted above,
through various rate orders issued by the NYPSC,  MADTE and NHPUC, costs related
to MGP  environmental  cleanup  activities are recovered in rates charged to gas
distribution  customers  and, as a result,  these  adjustments  to these reserve
balances did not impact earnings.


                                       89
<PAGE>


We estimate that the  remaining  cost of our MGP related  environmental  cleanup
activities,  including costs associated with the Ravenswood  Generating Station,
will be  approximately  $404.0 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, 2005, we have expended a total of
$174.0 million on environmental  investigation and remediation activities.  (See
Note 7 to  the  Consolidated  Financial  Statements,  "Contractual  Obligations,
Guarantees and Contingencies" for a further explanation of these matters.)

Market and Credit Risk Management Activities

Market Risk: KeySpan is exposed to market risk arising from potential changes in
one or more market variables,  such as energy commodity 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


                                       90
<PAGE>


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.

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

New York and Long Island
------------------------

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  companion policy  statements  regarding its vision for the
future of competitive  markets and guidelines for separately stating the cost of
competitive  services  currently  performed by New York  utilities.  The NYPSC's
vision  for the future of  competitive  markets,  as stated in the first  policy
statement, remains unchanged. Items of importance 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.

The NYPSC's second policy  statement of August 2004 addresses the means by which
New  York  utilities  should  state  separately,  or  "unbundle,"  the  costs of
competitive  and  potentially   competitive   services  currently  performed  by
utilities from the cost of providing local distribution  service.  The objective
of  unbundling  is  to  facilitate   competition  by  providing  customers  with
information as to savings  available from purchasing  competitive  services from
third-party providers, and to credit the customer's utility bill for the cost of
unbundled   services  when  they  migrate  to  purchase  them  from  competitive


                                       91
<PAGE>


suppliers.  In its unbundling policy statement,  the NYPSC directed utilities to
file with their next base rate  proceedings  updated cost studies for  unbundled
competitive  services that, once approved by the NYPSC,  would replace  existing
backout credits for these services established in prior utility proceedings. The
NYPSC  also  asked  utilities  to file with the  unbundled  cost  studies a lost
revenue  recovery  mechanism  that would  permit the utility to recover  revenue
associated  with the  difference  between  the cost the utility is able to avoid
when a customer  migrates to a  competitive  service  provider and the unbundled
rate for that service credited to the customer's bill.

KEDNY's and KEDLI's current  backout  credits for the billing  function are both
$.78 per  account  per month,  and were  established  in May 2001 by the NYPSC's
Order  Establishing  Retail  Access  Billing and Payment  Processing  Practices.
Pursuant  to  that  Order,   customers  that  purchase  commodity  service  from
third-party providers and receive a consolidated bill from the utility receive a
$.78  billing  credit on their  utility  bills.  KEDNY/KEDLI  then  invoices the
third-party  commodity  provider  for the  billing  service at the same $.78 per
account per month that is credited to the  customer's  utility  bill. As for the
commodity  merchant  function,  KEDNY's and KEDLI's existing backout credits are
$.21/Dth and $.19/Dth,  respectively,  as established in May 2002 by the NYPSC's
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 also
established  Transition  Balancing Accounts ("TBA") for KEDNY and KEDLI that are
funded by property  tax refunds and other sums due to firm gas sales  customers.
The TBAs are currently  the  mechanisms  for KEDNY and KEDLI to recover  revenue
lost to the merchant  function backout credit.  While the Joint Proposal expired
in November 2003, the KEDNY and KEDLI tariffs provide that the merchant function
backout  credits and the TBAs will remain in effect until November 2006. As part
of a retail choice program, KEDNY and KEDLI will propose a program to facilitate
competition  in  their  service  territories,  cost-based  unbundled  rates  for
competitive  services,  and a lost revenue recovery mechanism that prevents them
from being harmed by the migration of customers to competitive services.

On December 5, 2005, a petition was filed with the NYPSC requesting authority to
defer costs  associated  with high gas prices that are not reflected in existing
gas sales rates, including commodity-related  uncollectible expense, gas working
capital and gas in storage.  The NYPSC  commenced the required  45-day notice of
this petition in the New York State Register on January 25, 2006.

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


                                       92
<PAGE>


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.

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.  On June 6,
2005,  the  MADTE  issued  an order  in its  continuing  investigation  into gas
unbundling and found that  mandatory  capacity  assignment  should be continued,
including  continuation  of slice of system  versus path  method of  assignment,
essentially maintaining the status-quo.

Beginning on November 1, 2001, the NHPUC began  requiring gas utilities to offer
transportation services to all commercial and residential customers.  Since such
time EnergyNorth has provided such  transportation  in accordance with the NHPUC
order.

Electric Industry

10-Minute Spinning and Non-Spinning Reserves
--------------------------------------------

Due to the  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 such reserves,  as well as requiring a refunding of so
called alleged "excess payments"  received by sellers,  including the Ravenswood
Facility. 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 NYISO's other requests, such as
a bid cap for spinning reserves,  retroactive refunds,  recalculation of reserve
prices, etc., were rejected.

The NYISO, The Consolidated  Edison Company of New York ("Con Edison"),  Niagara
Mohawk  Power  Corporation  and  Rochester  Gas and Electric  each  individually
appealed FERC's order in federal court. The appeals were  consolidated  into one
case and 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 (the "Decision"). Essentially, the Court found errors in FERC's order
and remanded some issues back to FERC for further explanation and action.

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 March 4, 2005,  FERC issued an order  upholding  its
original  decision  not  to  order  refunds.  FERC  also  provided  the  further
explanation requested by the Court as to why refunds were not being ordered. The


                                       93
<PAGE>


NYISO and other market  participants  requested rehearing of FERC's latest order
and on November 17, 2005, FERC denied those requests.  The NYISO and various New
York  Transmission  Owners appealed FERC's November 17, 2005 order to the United
States Court of Appeals for the District of Columbia.

May 2000 Energy Market Clearing Prices
--------------------------------------

Due to unseasonably warm weather and scheduled  maintenance outages in May 2000,
energy prices spiked,  and the NYISO revised prices downward after it determined
a market  design flaw existed  which caused  prices to be higher than what would
occur in a  competitive  market.  FERC  originally  agreed  with the NYISO,  but
reversed its original decision on remand from the Court of Appeals.  On March 4,
2005,  FERC issued an order requiring the NYISO to reinstate the original prices
for May 8 and 9, 2000 and to pay suppliers,  including the Ravenswood  Facility,
accordingly.  In 2005, the Ravenswood Generating Station received a $9.2 million
increase  in its  payments  for its May 2000 energy  sales.  The NYISO and other
market  participants  requested  rehearing  of this March 4, 2005 order,  and on
November 22, 2005,  FERC denied those  requests.  The NYISO and various New York
Transmission Owners appealed FERC's November 22, 2005 order to the United States
Court of Appeals for the District of Columbia.

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.  On May 13, 2005, this appeal
was denied.

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. The NYISO reported that SMD2 is performing as expected,  and they continue
to monitor the market improvements.


                                       94
<PAGE>


The Ravenswood Generating Station and our New York City Operations
------------------------------------------------------------------

Currently, the NYISO's New York City local reliability rules require that 80% of
the  electric  capacity  needs  of  New  York  City  be  provided  by  "in-City"
generators.  On  February  6, 2006,  the NYISO  Board  increased  the  "in-City"
generator  requirement to 83% beginning in May 2006 through the period ending on
April 2007, based in part on the statewide reserve margin of 118% set by the New
York  State  Reliability  Council.  Our  Ravenswood  Generating  Station  is  an
"in-City"  generator.  As the electric  infrastructure  in New York City and the
surrounding  areas  continues  to change and evolve and the demand for  electric
power increases,  the "in-City" generator requirement could be further modified.
Construction of new transmission and generation facilities may cause significant
changes to the market for sales of capacity,  energy and ancillary services from
our Ravenswood Generating Station.  Recently 500 MW of capacity came on line and
it is  anticipated  that another  500MW of new capacity may be available  during
2006 as a result of the completion of an in-City  generation  project  currently
under  construction.  We can not,  however,  be certain as to when the new power
plant  will be in  operation  or the  nature  of future  New York  City  energy,
capacity or ancillary services market requirements or design.

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.  Seneca-Upshur  utilizes  OTC natural gas swaps to hedge
cash flow  variability  associated  with  forecasted  sales of natural  gas. The
Ravenswood Generating Station uses derivative financial instruments to hedge the
cash flow  variability  associated with the purchase of a portion of natural gas
or fuel oil that will be consumed  during the  generation  of  electricity.  The
Ravenswood  Generating Station also hedges the cash flow variability  associated
with a portion of electric  energy  sales.  During  2005,  our gas  distribution
operations utilized  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.  These derivative positions have
all settled as of December 31, 2005.

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




                                       95
<PAGE>

The following  tables set forth selected  financial data  associated  with these
derivative financial instruments that were outstanding at December 31, 2005.
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------
                                          Year of         Volumes     Fixed Price       Current Price              Fair Value
              Type of Contract            Maturity         (mmcf)         ($)                ($)                   ($Millions)
-----------------------------------------------------------------------------------------------------------------------------
                     Gas
<S>                                         <C>            <C>       <C>               <C>                             <C>
OTC Swaps - Short Natural Gas                2006           2,035     6.17 - 6.29       10.67 - 12.04                   (8.6)
                                             2007           1,691     5.86 - 5.97        9.81 - 12.49                   (8.1)
                                             2008           1,549     6.77 - 6.85        8.91 - 11.52                   (4.5)
-----------------------------------------------------------------------------------------------------------------------------
                                                            5,275                                                      (21.2)
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------
                                        Year of      Volumes      Fixed Price          Current Price            Fair Value
           Type of Contract             Maturity    (Barrels)         ($)                    ($)                ($Millions)
---------------------------------------------------------------------------------------------------------------------------
                 Oil
<S>                                      <C>        <C>          <C>                   <C>                            <C>
Swaps - Long Heating Oil                  2006       2,056,794    39.65 - 67.75         56.00 - 57.80                 (6.3)
---------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------------
                                                     2,056,794                                                        (6.3)
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------
                                    Year of                          Fixed Price         Current Price            Fair Value
        Type of Contract            Maturity            MWh              ($)                   ($)                ($Millions)
-----------------------------------------------------------------------------------------------------------------------------
          Electricity
<S>                                  <C>             <C>           <C>                  <C>                            <C>
Swaps - Energy                        2006            1,648,000     76.00 - 208.00       107.61 - 153.25                9.4
----------------------------------------------------------------------------------------------------------------------------
</TABLE>
The  following  tables  detail the  changes in and sources of fair value for the
above derivatives:
-------------------------------------------------------------------------------
(In Millions of Dollars)                                                2005
Change in Fair Value of Derivative Hedging Instruments              ($Millions)
-------------------------------------------------------------------------------
Fair value of contracts at January 1, 2005                              $ (1.4)
Net losses on contracts realized                                          36.6
Decrease in fair value of all open contracts                             (53.3)
-------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31,                    $ (18.1)
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
(In Millions 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                $ (9.2)                $ (12.6)          $ (21.8)
Local published indicies                 3.7                       -               3.7
----------------------------------------------------------------------------------------------
                                      $ (5.5)                $ (12.6)          $ (18.1)
----------------------------------------------------------------------------------------------
</TABLE>

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, 2005,  a 10%  increase/decrease  in heating oil and
natural gas prices would  decrease/increase the value of derivative  instruments
maturing  in one  year by $2.2  million.  Further,  a 10%  increase/decrease  in
electricity  and fuel prices  would  decrease/increase  the value of  derivative
instruments maturing in one year by $9.7 million.

                                       96
<PAGE>


Firm Gas Sales Derivative  Instruments - Regulated Utilities:  We use derivative
financial  instruments to reduce the cash flow  variability  associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations.  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, 2005.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                        Year of        Volumes       Floor          Ceiling      Fixed Price         Current Price       Fair Value
  Type of Contract      Maturity        (mmcf)        ($)              ($)            ($)                ($)             ($Millions)
------------------------------------------------------------------------------------------------------------------------------------
<S>                       <C>          <C>       <C>              <C>            <C>               <C>                     <C>
Options                    2006          7,200    5.50 - 12.00     5.50 - 13.55             -        8.75 - 13.06            15.6

Swaps                      2006         52,030              -                -    5.34 - 14.16      10.29 - 11.36           115.9
                           2007         20,480              -                -    6.81 - 11.99       9.44 - 11.88            26.1
------------------------------------------------------------------------------------------------------------------------------------
                                        79,710                                                                              157.6
------------------------------------------------------------------------------------------------------------------------------------
</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.








                                       97
<PAGE>

Item 8. Financial Statements and Supplementary Data

<TABLE>
<CAPTION>
                           CONSOLIDATED BALANCE SHEET


----------------------------------------------------------------------------------------------------------------------
                                                                                                December 31,
(In Millions of Dollars)                                                                2005                    2004
----------------------------------------------------------------------------------------------------------------------

ASSETS
<S>                                                                                 <C>                     <C>
Current Assets
     Cash and temporary cash investments                                           $    124.5              $    922.0
     Restricted cash                                                                     13.2                       -
     Accounts receivable                                                              1,035.6                   788.5
     Unbilled revenue                                                                   685.6                   590.8
     Allowance for uncollectible accounts                                               (62.8)                  (67.8)
     Gas in storage, at average cost                                                    766.9                   515.5
     Material and supplies, at average cost                                             140.5                   123.4
     Derivative contracts                                                               142.8                     0.6
     Other                                                                              173.8                   162.7
     Assets of discontinued operations                                                      -                    42.9
                                                                       -----------------------------------------------
                                                                                      3,020.1                 3,078.6
                                                                       -----------------------------------------------

Investments and  Other                                                                  242.4                   272.9
                                                                       -----------------------------------------------

Property
     Gas                                                                              7,275.9                 6,871.2
     Electric                                                                         2,492.3                 2,402.1
     Other                                                                              416.3                   398.6
     Accumulated depreciation                                                        (2,922.6)               (2,702.3)
     Gas exploration and production, at cost                                            184.2                   187.1
     Accumulated depletion                                                             (109.2)                  (97.5)
     Property of discontinued operations                                                    -                     8.7
                                                                       -----------------------------------------------
                                                                                      7,336.9                 7,067.9
                                                                       -----------------------------------------------

Deferred Charges
     Regulatory assets
       Miscellaneous assets                                                             688.3                   535.3
       Derivative contracts                                                              30.9                    20.1
     Goodwill and other intangible assets, net of amortization                        1,666.3                 1,677.6
     Derivative contracts                                                                75.2                    29.2
     Other                                                                              752.5                   682.5
                                                                       -----------------------------------------------
                                                                                      3,213.2                 2,944.7
                                                                       -----------------------------------------------

Total Assets                                                                       $ 13,812.6              $ 13,364.1
                                                                       ===============================================
----------------------------------------------------------------------------------------------------------------------
</TABLE>
        See accompanying Notes to the Consolidated Financial Statements.



                                       98
<PAGE>

<TABLE>
<CAPTION>
                           CONSOLIDATED BALANCE SHEET


-----------------------------------------------------------------------------------------------------------------------
                                                                                                 December 31,
(In Millions of Dollars)                                                                  2005                   2004
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>                     <C>
LIABILITIES AND CAPITALIZATION
Current Liabilities
     Accounts payable and other liabilities                                        $    1,087.0             $    906.7
     Commercial paper                                                                     657.6                  912.2
     Current maturities of long-term debt & capital leases                                 13.0                   16.1
     Current redemption requirement of preferred stock                                        -                   55.3
     Taxes accrued                                                                        176.3                  161.6
     Dividends payable                                                                     81.1                   74.1
     Customer deposits                                                                     39.1                   43.3
     Interest accrued                                                                      53.8                   48.8
     Other current liability, derivative contracts                                         47.3                      -
     Liabilities of discontinued operations                                                   -                   64.2
                                                                         ----------------------------------------------
                                                                                        2,155.2                2,282.3
                                                                         ----------------------------------------------

Deferred Credits and Other Liabilities
     Regulatory liabilities:
       Miscellaneous liabilities                                                           69.9                   66.5
       Removal costs recovered                                                            516.4                  496.5
       Derivative accounts                                                                175.4                    7.4
     Asset retirement obligations                                                          47.4                    1.9
     Deferred income tax                                                                1,157.9                1,124.1
     Postretirement benefits and other reserves                                         1,118.4                  900.4
     Derivative contracts                                                                  44.3                   43.9
     Other                                                                                127.5                   94.3
                                                                         ----------------------------------------------
                                                                                        3,257.2                2,735.0
                                                                         ----------------------------------------------

Commitments and Contingencies (See Note 7)                                                    -                      -

Capitalization
     Common stock                                                                       3,975.9                3,502.0
     Retained earnings                                                                    866.9                  792.2
     Accumulated other comprehensive income                                               (74.8)                 (54.3)
     Treasury stock                                                                      (303.9)                (345.1)
                                                                         ----------------------------------------------
          Total common shareholders' equity                                             4,464.1                3,894.8
     Preferred stock                                                                          -                   19.7
     Long-term debt and capital leases                                                  3,920.8                4,418.7
                                                                         ----------------------------------------------
Total Capitalization                                                                    8,384.9                8,333.2
                                                                         ----------------------------------------------

Minority Interest in Consolidated Companies                                                15.3                   13.6
                                                                         ----------------------------------------------
Total Liabilities and Capitalization                                                 $ 13,812.6             $ 13,364.1
                                                                         ==============================================
</TABLE>

        See accompanying Notes to the Consolidated Financial Statements.


                                       99
<PAGE>

<TABLE>
<CAPTION>
                        CONSOLIDATED STATEMENT OF INCOME
---------------------------------------------------------------------------------------------------------------------------
                                                                                        Year Ended December 31,
(In Millions of Dollars, Except Per Share Amounts)                            2005                2004               2003
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                 <C>                <C>
Revenues
     Gas Distribution                                                     $ 5,390.1           $ 4,407.3          $ 4,161.3
     Electric Services                                                      2,042.7             1,738.7            1,606.0
     Energy Services                                                          191.2               182.4              158.9
     Houston Exploration                                                          -               268.1              495.3
     Energy Investments                                                        38.0                54.0              114.0
                                                                -----------------------------------------------------------
Total Revenues                                                              7,662.0             6,650.5            6,535.5
                                                                -----------------------------------------------------------
Operating Expenses
     Purchased gas for resale                                               3,597.3             2,664.5            2,495.1
     Fuel and purchased power                                                 752.1               540.3              414.6
     Operations and maintenance                                             1,617.9             1,567.0            1,622.6
     Depreciation, depletion and amortization                                 396.5               551.8              571.7
     Operating taxes                                                          407.1               404.2              418.2
     Impairment charges                                                           -                41.0                  -
                                                                -----------------------------------------------------------
Total Operating Expenses                                                    6,770.9             5,768.8            5,522.2
                                                                -----------------------------------------------------------
Gain on sale of property                                                        1.6                 7.0               15.1
Income from equity investments                                                 15.1                46.5               19.2
                                                                -----------------------------------------------------------
Operating Income                                                              907.8               935.3            1,047.6
                                                                -----------------------------------------------------------
Other Income and (Deductions)
     Interest charges                                                        (269.3)             (331.3)            (307.7)
     Sale of subsidiary stock                                                   4.1               388.3               13.3
     Cost of debt redemption                                                  (20.9)              (45.9)             (24.1)
     Minority interest                                                         (0.4)              (36.8)             (63.9)
     Other                                                                     16.6                30.6               42.1
                                                                -----------------------------------------------------------
Total Other Income and (Deductions)                                          (269.9)                4.9             (340.3)
                                                                -----------------------------------------------------------
Income Taxes
     Current                                                                  206.6               201.9              (99.8)
     Deferred                                                                  32.7               123.6              381.1
                                                                -----------------------------------------------------------
Total Income Taxes                                                            239.3               325.5              281.3
                                                                -----------------------------------------------------------
Earnings from Continuing Operations                                           398.6               614.7              426.0
                                                                -----------------------------------------------------------
Discontinued Operations
    Income (loss) from operations, net of tax                                  (4.1)              (79.0)              (1.9)
    Gain (Loss) on disposal, net of tax                                         2.3               (72.0)                 -
                                                                -----------------------------------------------------------
    Loss from Discontinued Operations                                          (1.8)             (151.0)              (1.9)
                                                                -----------------------------------------------------------
Cumulative Change in Accounting Principles, net of tax                         (6.6)                  -              (37.4)
                                                                -----------------------------------------------------------
Net Income                                                                    390.2               463.7              386.7
Preferred stock dividend requirements                                           2.2                 5.6                5.8
                                                                -----------------------------------------------------------
Earnings for Common Stock                                                 $   388.0           $   458.1          $   380.9
                                                                ===========================================================
Basic Earnings Per Share
  Continuing Operations, less preferred stock dividends                   $    2.33           $    3.80          $    2.65
  Discontinued Operations                                                     (0.01)              (0.94)             (0.01)
  Cumulative Change in Accounting Principles                                  (0.04)                  -              (0.23)
                                                                -----------------------------------------------------------
Basic Earnings Per Share                                                  $    2.28           $    2.86          $    2.41
                                                                ===========================================================
Diluted Earnings Per Share
  Continuing Operations, less preferred stock dividends                   $    2.32           $    3.78          $    2.63
  Discontinued Operations                                                     (0.01)              (0.94)             (0.01)
  Cumulative Change in Accounting Principles                                  (0.04)                  -              (0.23)
                                                                -----------------------------------------------------------
Diluted Earnings Per Share                                                $    2.27           $    2.84          $    2.39
                                                                ===========================================================
Average Common Shares Outstanding (000)                                     169,940             160,294            158,256
Average Common Shares Outstanding - Diluted (000)                           170,801             161,277            159,232
---------------------------------------------------------------------------------------------------------------------------
</TABLE>
        See accompanying Notes to the Consolidated Financial Statements.

                                       100
<PAGE>

<TABLE>
<CAPTION>
                      CONSOLIDATED STATEMENT OF CASH FLOWS
------------------------------------------------------------------------------------------------------------------------------
                                                                                          Year Ended December 31,
(In Millions of Dollars)                                                         2005               2004               2003
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>                <C>                 <C>
Operating Activities
Net income                                                                    $  390.2           $  463.7            $  386.7
Adjustments to reconcile net income to net
      cash provided by (used in) operating activities
    Depreciation, depletion and amortization                                     396.5              551.8               571.7
    Deferred income tax                                                           32.7              123.6               188.7
    Income from equity investments                                               (15.1)             (46.5)              (18.0)
    Dividends from equity investments                                              9.3               14.2                 2.8
    Amortization of financing fees / interest rate swaps                          (1.4)             (14.9)               (9.9)
    Gain on sale of investments and property                                      (5.6)            (395.3)              (28.5)
    Hedging (gain)/losses                                                         (3.2)               2.5                (1.0)
    Amortization of property taxes                                               126.2              101.9                87.5
    Impairment charges                                                               -               41.0                   -
    Loss from discontinued operations                                              1.8              151.0                 1.9
    Cumulative change in accounting principle                                      6.6                  -                37.4
    Environmental reserve adjustment                                                 -                  -               (10.5)
    Minority interest                                                              0.4               36.8                63.9
Changes in assets and liabilities
    Accounts receivable                                                         (305.7)            (234.2)               60.4
    Materials and supplies, fuel oil and gas in storage                         (268.4)             (39.0)             (199.0)
    Accounts payable and accrued expenses                                        196.3              159.5               225.8
    Prepaid property taxes                                                      (136.2)            (112.1)             (133.9)
    Reserve payments                                                             (35.7)             (37.3)              (36.5)
    Insurance settlements                                                         21.1                  -                   -
    Other                                                                         (6.5)             (16.6)               33.9
                                                                    ----------------------------------------------------------
Net Cash Provided by Continuing Operating Activities                             403.3              750.1             1,223.4
                                                                    ----------------------------------------------------------
Investing Activities
    Construction expenditures                                                   (539.5)            (750.3)           (1,009.4)
    Cost of removal                                                              (27.8)             (36.3)              (31.1)
    Net proceeds from sale of property and investments                            47.0            1,021.3               309.7
    Derivative margin call                                                        (8.9)                 -                   -
    Other investments                                                                -                  -              (211.3)
    Issuance of long-term note                                                       -                  -               (55.0)
                                                                    ----------------------------------------------------------
Net Cash (Used in) Provided by Continuing Investing Activities                  (529.2)             234.7              (997.1)
                                                                    ----------------------------------------------------------
Financing Activities
    Treasury stock issued                                                         41.2               33.4                96.7
    Common stock issuance                                                        460.0                  -               473.6
    Issuance of long-term debt                                                       -               49.3             1,024.5
    Payment of long-term debt                                                   (515.0)            (920.1)             (614.3)
    Issuance / (payment) of commercial paper                                    (254.6)             430.4              (433.8)
    Redemption of preferred stock                                                (75.0)              (8.5)              (14.3)
    Net proceeds from sale/leasback transaction                                      -              382.0                   -
    Redemption of promissory notes                                                   -                  -              (447.0)
    Common and preferred stock dividends paid                                   (308.4)            (291.1)             (280.6)
    Gain on interest rate swap                                                       -               12.7                   -
    Other                                                                         (5.4)              36.1                15.0
                                                                    ----------------------------------------------------------
Net Cash (Used in) Continuing Financing Activities                              (657.2)            (275.8)             (180.2)
                                                                    ----------------------------------------------------------
Net Increase in Cash and Cash Equivalents                                     $ (783.1)           $ 709.0              $ 46.1
Cash Flow from Discontinued Operations - Operating Activities*                    (3.8)               8.1               (16.5)
Cash Flow from Discontinued Operations - Investing Activities*                   (10.6)               1.3                 2.3
Cash Flow from Discontinued Operations - Financing Activities*                       -                0.2                 0.9
Cash and Cash Equivalents at Beginning of Period                                 922.0              203.4               170.6
                                                                    ----------------------------------------------------------
Cash and Cash Equivalents at End of Period                                    $  124.5            $ 922.0             $ 203.4
                                                                    ==========================================================
Interest Paid                                                                 $  262.7            $ 336.5             $ 355.1
Income Tax Paid                                                               $  181.5            $ 122.0             $  65.5
------------------------------------------------------------------------------------------------------------------------------
</TABLE>
                *Revised - See Note 1

        See accompanying Notes to the Consolidated Financial Statements.


                                      101
<PAGE>


<TABLE>
<CAPTION>
                   CONSOLIDATED STATEMENT OF RETAINED EARNINGS

------------------------------------------------------------------------------------------------------------------
                                                                                Year Ended December 31,
(In  Millions of Dollars)                                            2005                2004               2003
------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>                 <C>                <C>
Balance at Beginning of Period                                    $  792.2            $  621.4           $  522.8
Net Income for Period                                                390.2               463.7              386.7
------------------------------------------------------------------------------------------------------------------
                                                                   1,182.4             1,085.1              909.5
Deductions:
Cash dividends declared on common stock                              313.3               287.3              282.3
Cash dividends declared on preferred stock                             2.2                 5.6                5.8
------------------------------------------------------------------------------------------------------------------
Balance at End of Period                                          $  866.9            $  792.2           $  621.4
------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME


-------------------------------------------------------------------------------------------------------------------------------
                                                                                            Year Ended December 31,
(In Millions of Dollars)                                                         2005                2004               2003
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>                 <C>                 <C>
Net Income                                                                     $ 390.2             $ 463.7             $ 386.7
-------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income, net of tax
Net losses (gains) on derivative instruments                                      23.8                (0.3)               23.0
Unrealized (losses) gains on derivative financial instruments                    (35.1)               15.4               (25.4)
Deconsolidation of certain subsidiaries                                              -                 9.3                   -
Foreign currency translation adjustments                                          (5.0)              (21.5)               28.7
Unrealized gains (losses) on marketable securities                                (0.5)                7.1                 8.5
Premium on derivative instrument                                                     -                 3.4                (3.4)
Accrued unfunded pension obligation                                               (3.7)               (7.8)                8.4
-------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax                                    (20.5)                5.6                39.8
-------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income                                                           $ 369.7             $ 469.3             $ 426.5
-------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Net losses (gains) on derivative instruments                                      12.8                (0.2)               12.4
Unrealized (losses) gains on derivative financial instruments                    (20.7)                8.2               (13.6)
Deconsolidation of certain subsidiaries                                              -                 5.0                   -
Foreign currency translation adjustments                                          (2.7)              (11.6)               15.4
Unrealized gains (losses) on marketable securities                                (0.2)                3.8                 4.6
Accrued unfunded pension obligation                                               (2.1)               (4.2)                4.5
Premium on derivative instrument                                                     -                 1.9                (1.9)
-------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense                                                    $ (12.9)            $   2.9             $  21.4
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>


        See accompanying Notes to the Consolidated Financial Statements.




                                      102
<PAGE>

<TABLE>
<CAPTION>
                    CONSOLIDATED STATEMENT OF CAPITALIZATION


-----------------------------------------------------------------------------------------------------------------------------------
                                                                 December 31,                                 December 31,
(In Millions of Dollars)                                  2005                 2004                     2005                2004
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                <C>                         <C>                 <C>
Common Shareholders' Equity                                     Shares Issued
Common stock, $0.01 par value                           184,864,124        172,737,654               $     1.7           $     1.7
Premium on capital stock                                                                               3,974.2             3,500.3
Retained earnings                                                                                        866.9               792.2
Other comprehensive income                                                                               (74.8)              (54.3)
Treasury stock                                          (10,495,743)       (11,919,343)                 (303.9)             (345.1)
-----------------------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity                       174,368,381        160,818,311                 4,464.1             3,894.8
-----------------------------------------------------------------------------------------------------------------------------------

Preferred Stock - Redemption Required
Par Value $100 per share
7.07% Series B -private placement                                 -            553,000                       -                55.3
7.17% Series C-private placement                                  -            197,000                       -                19.7
Less: current redemption requirements                             -           (553,000)                      -               (55.3)
-----------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required                       -            197,000                       -                19.7
-----------------------------------------------------------------------------------------------------------------------------------

-----------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt                                      Interest Rate          Maturity
-----------------------------------------------------------------------------------------------------------------------------------

Medium and Long Term Notes                            4.65% - 9.75%        2006 - 2035                 2,437.2             2,485.0

Gas Facilities Revenue Bonds                            Variable           2020 - 2026                   230.0               125.0
                                                      4.70% - 6.95%        2020 - 2026                   410.5               515.5
-----------------------------------------------------------------------------------------------------------------------------------
Total Gas Facilities Revenue Bonds                                                                       640.5               640.5
-----------------------------------------------------------------------------------------------------------------------------------
Promissory Notes to LIPA

Pollution Control Revenue Bonds                           5.15%            2016 - 2028                   108.0               108.0
Electric Facilities Revenue Bonds                         5.30%            2023 - 2027                    47.4                47.4
-----------------------------------------------------------------------------------------------------------------------------------
Total Promissory Notes to LIPA                                                                           155.4               155.4
-----------------------------------------------------------------------------------------------------------------------------------

MEDS Equity Units                                         8.75%               2005                           -               460.0
Industrial Development Bonds                              5.25%               2027                       128.3               128.3
First Mortgage Bonds                                  6.08% - 8.80%        2008 - 2028                    95.0                95.0
Authority Financing Notes                               Variable           2027 - 2028                    66.0                66.0
Ravenswood Master Lease & Capital Leases                                   2006 - 2022                   423.0               424.1
-----------------------------------------------------------------------------------------------------------------------------------
Subtotal                                                                                               3,945.4             4,454.3
                                                                                                                                 -
                                                                                                                                 -
Unamortized interest rate hedge and debt discount                                                        (30.4)              (55.2)
Derivative impact on debt                                                                                 18.8                35.7
Less: current maturities                                                                                  13.0                16.1
-----------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt                                                                                   3,920.8             4,418.7
-----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                                                                 $ 8,384.9           $ 8,333.2
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

        See accompanying Notes to the Consolidated Financial Statements.


                                      103
<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."

On February 25, 2006,  Keyspan entered into an Agreement and Plan of Merger (the
"Merger   Agreement"),   with  National  Grid  PLC,  a  public  limited  company
incorporated  under the laws of England and Wales  ("Parent")  and National Grid
USA, Inc, a New York  Corporation  ("Merger Sub"),  pursuant to which Merger Sub
will merge with and into KeySpan (the "Merger"),  with KeySpan continuing as the
surviving  Company.  Pursuant to the Merger Agreement,  at the effective time of
the Merger,  each outstanding share of common stock, par value $.01 per share of
KeySpan (the  "Shares"),  other than shares owned by KeySpan,  shall be canceled
and  shall be  converted  into the  right to  receive  $42.00  in cash,  without
interest.

Consummation of the Merger is subject to various closing  conditions,  including
but not  limited  to the  satisfaction  or waiver of  conditions  regarding  the
receipt  of  requisite  regulatory  approvals  and the  adoption  of the  Merger
Agreement by the  stockholders  of KeySpan and the Parent.  Assuming  receipt or
waiver of the  foregoing,  it is currently  anticipated  that the Merger will be
consummated  in early 2007.  However,  no assurance can be given that the Merger
will occur, or, the timing of its completion.

KeySpan's core businesses are engaged in gas distribution, electric services and
generation  and other energy  related  activities.  KeySpan's  gas  distribution
operations  are  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 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").  On February 1, 2006,  KeySpan and LIPA  entered  into  agreements  to
extend, amend and restate these contractual arrangements. See Note 11 "2006 LIPA
Settlement" for a discussion of the settlement.

Our other  subsidiaries are involved in gas production;  gas storage;  liquefied
natural gas storage;  retail electric marketing;  appliance service; 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.)




                                      104
<PAGE>

At December 31, 2005,  KeySpan was a holding  company  under the Public  Utility
Holding  Company Act of 1935, as amended  ("PUCHA  1935").  In August 2005,  the
Energy  Policy Act of 2005 (the "Energy  Act") was enacted.  The Energy Act is a
broad energy bill that places an increased  emphasis on the production of energy
and promotes the development of new technologies and alternative  energy sources
and provides  tax credits to companies  that  produce  natural gas,  oil,  coal,
electricity  and  renewable  energy.  For KeySpan,  one of the more  significant
provisions of the Energy Act is the repeal of PUHCA 1935, which became effective
on February 8, 2006, and the transfer of certain holding company  oversight from
the Securities and Exchange  Commission ("SEC") to the Federal Energy Regulatory
Commission  ("FERC")  pursuant to the Public Utility Holding Company Act of 2005
("PUHCA 2005').

Pursuant  to PUHCA  2005,  the SEC no longer has  jurisdiction  over our holding
company  activities,  other  than those  associated  with the  registration  and
issuance of our  securities  under the  federal  securities  laws.  FERC now has
jurisdiction  over  certain of our holding  company  activities,  including  (i)
regulating certain  transactions among our affiliates within our holding company
system;  (ii) governing the issuance,  acquisition and disposition of securities
and assets by certain of our public utility  subsidiaries;  and (iii)  approving
certain utility mergers and acquisitions.

Moreover,  our affiliate transactions also remain subject to certain regulations
of the  Public  Service  Commission  of the  State  of New York  ("NYPSC"),  the
Massachusetts  Department of Telecommunications and Energy ("MADTE") and the New
Hampshire Public Utility Commission ("NHPUC") in addition to FERC.

Under our holding company structure, we have no independent operations or source
of income of our own and conduct all of our operations  through our subsidiaries
and, as a result,  we depend on the earnings and cash flow of, and  dividends or
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.

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.

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 all
periods presented,  KeySpan revised and has separately  disclosed the operating,
investing  and  financing  portions  of  the  cash  flows  attributable  to  its
discontinued  operations,  which in prior  periods  were  reported on a combined
basis as a single amount.

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 NYPSC,  the
NHPUC,  and the MADTE. Our electric  generation  subsidiaries are not subject to


                                      105
<PAGE>


state rate regulation,  but they are subject to 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.

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, 2005 and
December 31, 2004.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
                                                                         December 31,
(In Millions of Dollars)                                           2005                2004
---------------------------------------------------------------------------------------------
<S>                                                              <C>                 <C>
Regulatory Assets
Regulatory tax asset                                             $  33.4             $  39.5
Property and other taxes                                            53.8                58.8
Environmental costs                                                454.7               272.6
Postretirement benefits                                            109.3               110.6
Costs associated with the KeySpan/LILCO transaction                 27.3                39.1
Derivative financial instruments                                    30.9                20.1
Other                                                                9.8                14.7
---------------------------------------------------------------------------------------------
Total Regulatory Assets                                          $ 719.2             $ 555.4
Regulatory Liabilities                                            (245.3)              (73.9)
---------------------------------------------------------------------------------------------
Net Regulatory Assets                                              473.9               481.5
Removal Costs Recovered                                           (516.4)             (496.5)
---------------------------------------------------------------------------------------------
                                                                 $ (42.5)            $ (15.0)
---------------------------------------------------------------------------------------------
</TABLE>

The regulatory assets above are not included in utility 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  except for the current  market value of our  derivative
financial  instruments.  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 $11.3  million and $37.7  million at December 31, 2005 and
December 31, 2004,  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 9 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


                                      106
<PAGE>


operations  may no longer meet the criteria for the  application  of SFAS 71. In
that event, a write-down of all or a portion of our existing  regulatory  assets
and  liabilities  could  result.  If we were  unable  to  continue  to apply the
provisions of SFAS 71 for any of our rate regulated subsidiaries, we would apply
the  provisions  of  SFAS  101,  "Regulated  Enterprises  -  Accounting  for the
Discontinuation  of  Application  of FASB  Statement  71." We estimate  that the
write-off  of  all  net   regulatory   assets  at  December  31,  2005,   before
consideration of removal costs recovered, could result in a charge to net income
of $308.0 million after-tax or $1.81 per share,  which would be classified as an
extraordinary item. 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.)

In  December  2005,  Boston Gas  received a MADTE  order  permitting  regulatory
recovery  of the 2004  gas  cost  component  of bad  debt  write-offs.  This was
approved for full recovery as an exogenous cost  effective  November 1, 2005. In
addition, effective January 1, 2006 Boston Gas is permitted to fully recover the
gas cost component of bad debt  write-offs  through its  cost-of-gas  adjustment
clause rather than filing for recovery as an exogenous  cost. We have  reflected
both of these favorable  recovery  mechanisms in our December 31, 2005 Allowance
for Doubtful Accounts reserve  requirement and related expense.  Boston Gas also
plans to request  full  recovery,  as an  exogenous  cost,  of the 2005 gas cost
component of bad debt write-offs beginning November 1, 2006.

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  250 MW  combined  cycle  generating
facility located at the Ravenswood facility site ("Ravenswood Expansion").


                                      107
<PAGE>


LIPA Agreements:

In 1998,  KeySpan and LIPA entered into three major long-term service agreements
that (i) provide to LIPA all operation,  maintenance and  construction  services
and significant  administrative  services relating to the Long Island T&D system
pursuant to the Management Services Agreement (the "1998 MSA"); (ii) supply LIPA
with electric generating capacity, energy conversion and ancillary services from
our Long Island  generating  units  pursuant to the Power Supply  Agreement (the
"1998 PSA"); 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 the Energy  Management  Agreement (the
"1998 EMA"). The 1998 MSA, 1998 PSA and 1998 EMA all are  collectively  referred
to as the 1998 LIPA Agreements and are discussed in greater detail below.

KeySpan manages the day-to-day operations,  maintenance and capital improvements
of the T&D system  under the 1998 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 1998 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 the 1998 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 1998 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 the
1998 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 1998 EMA provides incentives
and penalties that can total $5 million annually for performance related to fuel
purchases  and  off-system  power  purchases.  The 1998 EMA is expected to be in
effect  through 2013 for the  procurement  of fuel supplies and through 2006 for
off-system arrangement services.


                                      108
<PAGE>


On February 1, 2006,  KeySpan and LIPA  entered into (i) an amended and restated
Management  Services Agreement (the "2006 MSA"),  pursuant to which KeySpan will
continue to operate and  maintain  the electric T&D System owned by LIPA on Long
Island;  (ii) a new Option and  Purchase  and Sale  Agreement  (the "2006 Option
Agreement"),  to replace the Generation  Purchase Rights  Agreement (as amended,
the "GPRA"),  pursuant to which LIPA had the option,  through December 15, 2005,
to effectively acquire  substantially all of the electric generating  facilities
owned by KeySpan on Long  Island;  and (iii) a Settlement  Agreement  (the "2006
Settlement   Agreement")   resolving  outstanding  issues  between  the  parties
regarding the 1998 LIPA Agreements.  The 2006 MSA, the 2006 Option Agreement and
the 2006 Settlement  Agreement are collectively  referred to herein as the "2006
LIPA  Agreements".  Each of the 2006 LIPA Agreements will become effective as of
January  1, 2006 upon all of the 2006 LIPA  Agreements  receiving  the  required
governmental  approvals;  otherwise none of the 2006 LIPA Agreements will become
effective.  See Note 11, "2006 LIPA Settlement" for additional  details on these
agreements.

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") each.  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.

Ravenswood Facilities:

In addition,  electric  revenues are derived from our investment in the 2,200 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  Generation Station. (See Note 7
"Contractual   Obligations,   Financial  Guarantees  and  Contingencies"  for  a
description  of  the  financing  arrangements  associated  with  the  Ravenswood
Generation  Station.) We realize  revenues from our investment in the Ravenswood
Generation  Station  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 service and
maintenance   contracts   associated  with  small   commercial  and  residential
appliances are recognized as earned or over the life of the service contract, as
appropriate.  Revenues earned for engineering services are derived from services
rendered under fixed price and cost-plus  contracts and generally are recognized
on  the   percentage-of-completion   method.  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  $29.3 million and $28.5 million as of December 31, 2005,  and December
31, 2004, respectively. These balances represent primarily unearned revenues for
service contracts and are generally amortized to income over a one year period.


                                      109
<PAGE>


KeySpan completed its sale of its mechanical contracting companies in the first
quarter of 2005, and therefore, no longer has revenues form mechanical
contracting operations. (See Note 10 "Energy Services - Discontinued Operations"
for additional details on the mechanical contracting companies.)

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, 2005 ranged
from  1.80% to 7.02%.  Capitalized  interest  for  2005,  2004 and 2003 was $1.4
million, $7.4 million and $13.5 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 cost of removal through rates charged to customers as a portion
of  depreciation  expense.  At  December  31,  2005 and 2004,  KeySpan had costs
recovered  in  excess of costs  incurred  totaling  $516.4  million  and  $496.5
million, respectively. These amounts are reflected as a regulatory liability.

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,
                                        2005       2004        2003
---------------------------------------------------------------------
Electric                                3.75%      3.87%       3.81%
Gas                                     3.72%      3.55%       3.37%
---------------------------------------------------------------------
---------------------------------------------------------------------

We also had $416.3 million of other property at December 31, 2005, consisting of
assets held primarily by our corporate service  subsidiary of $290.0 million and
$96.0 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


                                      110
<PAGE>


depreciable  lives ranging from three to 40 years. We allocate the carrying cost
of these  assets to our  operating  subsidiaries  through  our filed  allocation
methodology.  Energy Services  assets consist largely of computer  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 energy  facilities  after a project has been determined to be probable
of completion.

F.  Gas Exploration and Production Property - Depletion

KeySpan  maintains gas  exploration  and production  activities  through its two
wholly-owned  subsidiaries - KeySpan  Exploration and Production,  LLC ("KeySpan
Exploration") and Seneca-Upshur Petroleum, Inc.  ("Seneca-Upshur").  At December
31, 2005, these subsidiaries had net exploration and production  property in the
amount of $75.0  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.

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 of December 31, 2005, we estimated that our capitalized  costs did not exceed
the ceiling test  limitation.  We used an average  wellhead  price of $10.43 per
MCF, adjusted for derivative instruments.

As a result of the  disposition  of Houston  Exploration  in 2004,  during  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.


                                      111
<PAGE>


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.

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,  for 2004 and 2003,  capitalized interest related to their
unevaluated  natural gas and oil properties,  as well as some  properties  under
development  which were not being  amortized.  For years ended December 31, 2004
and 2003, capitalized interest was $3.4 million and $7.3 million, respectively.

G.  Goodwill and Other Intangible Assets

The balance of goodwill and other intangible assets was $1.7 billion at December
31, 2005 and December 31, 2004, representing primarily the excess of acquisition
cost over the fair value of net assets  acquired.  Goodwill and other intangible
assets  reflect the  Eastern and  EnergyNorth  acquisitions,  the  KeySpan/LILCO
transaction,  as well as  acquisitions  of  non-utility  energy-related  service
companies  and also  relates to certain  ownership  interests  of 50% or less in
energy-related investments, which are accounted for under the equity method.

The table below summarizes the goodwill and other intangible  assets balance for
each segment at December 31, 2005 and 2004:

-----------------------------------------------------------------------
(In Millions of Dollars)                            At December 31,
                                                   2005         2004
-----------------------------------------------------------------------
Operating Segment

Gas Distribution                                $1,436.9      $1,436.9
Energy Services                                     65.2          65.8
Energy Investments and other                       164.2         174.9
-----------------------------------------------------------------------
                                                $1,666.3      $1,677.6
-----------------------------------------------------------------------

As prescribed in SFAS 142 "Goodwill  and Other  Intangible  Assets,"  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.  At December 31, 2005,  KeySpan
had $1.7 billion of recorded  goodwill and has concluded  that the fair value of
the business units that have recorded goodwill exceed their carrying value.

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.  (See  Note  10 to  the
Consolidated Financial Statements "Energy Services-Discontinued  Operations" for
further details.)


                                      112
<PAGE>


At the end of  2004,  KeySpan  entered  into an  agreement  to sell its then 50%
interest  in Premier  Transmission  Limited  ("Premier").  This  investment  was
accounted for under the equity  method of  accounting in the Energy  Investments
segment.  In the fourth  quarter  of 2004  KeySpan  recorded  a partial  pre-tax
non-cash  impairment  charge of $26.5 million - $18.8 million after-tax or $0.12
per  share.  The  impairment   charge  reflected  the  difference   between  the
anticipated  cash  proceeds  from the sale of Premier  compared to its  carrying
value at that time and was recorded as a reduction to goodwill.

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 currently outstanding  derivative instruments do
not  qualify as energy  trading  contracts  as  defined  by  current  accounting
literature.

Financially-Settled  Commodity  Derivative  Instruments:  We  employ  derivative
financial  instruments,  such as futures,  options and swaps, for the purpose of
hedging the cash flow variability associated with forecasted purchases and sales
of various  energy-related  commodities.  All such  derivative  instruments  are
accounted  for  pursuant  to  the  requirements  of  SFAS  133  "Accounting  for
Derivative  Instruments  and  Hedging  Activities,"  as  amended  by  SFAS  149,
"Amendment  of Statement  133  Derivative  Instruments  and Hedging  Activities"
(collectively,   "SFAS  133").  With  respect  to  those  commodity   derivative
instruments  that are  designated  and  accounted  for as cash flow hedges,  the
effective  portion of  periodic  changes in the fair  market  value of cash flow
hedges is recorded as other  comprehensive  income on the  Consolidated  Balance
Sheet, while the ineffective portion of such changes in fair value is recognized
in  earnings.  Unrealized  gains and losses (on such cash flow  hedges) that are
recorded  as other  comprehensive  income  are  subsequently  reclassified  into
earnings concurrent when hedged  transactions  impact earnings.  With respect to
those  commodity  derivative  instruments  that are not  designated  as  hedging
instruments,  such  derivatives  are accounted for on the  Consolidated  Balance
Sheet at fair value, with all changes in fair value reported in earnings.

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


                                      113
<PAGE>


Physically-Settled  Commodity Derivative  Instruments:  Certain of our contracts
for the physical purchase of natural gas were assessed as no longer being exempt
from the requirements of SFAS 133 as normal purchases.  As such, these contracts
are recorded on the  Consolidated  Balance Sheet at fair market value.  However,
since such contracts were executed for the purchases of natural gas that is sold
to regulated firm gas sales customers,  and pursuant to the requirements of SFAS
71,  changes in the fair  market  value of these  contracts  are  recorded  as a
regulatory asset or regulatory liability on the Consolidated Balance Sheet.

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

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

I.  Equity Investments

Certain  subsidiaries  own as their  principal  assets,  investments  (including
goodwill),  representing  ownership  interests of 50% or less in  energy-related
businesses that are accounted for under the equity method. None of these 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, 2005, 2004
and 2003,  excise taxes  collected and paid were $65.8  million,  $73.3 million,
$90.5 million, respectively.


                                      114
<PAGE>


K.  Subsidiary Common Stock Issuances to Third Parties

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

L.  Foreign Currency Translation

We followed 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,  the  foreign  currency
translation  adjustment  was included on the  Consolidated  Balance  Sheet.  The
functional  currency for our foreign  affiliates  was their local  currency.  At
December 31, 2005,  SFAS 52 was not applicable to KeySpan since we completed the
sale of our remaining foreign investment in the first quarter of 2005.

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.

At December 31, 2005, we had  approximately  4.6 million options  outstanding to
purchase  KeySpan common stock that were not used in the  calculation of diluted
EPS since the exercise price associated with these options were greater than the
average per share market price of Keyspan's  common  stock.  In addition,  there
were  approximately  384,000  performance  shares not used in the calculation of
diluted EPS since these  shares  would not have been issued if December 31, 2005
were  the end of the  performance  period.  In 2003,  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 Millions of Dollars, Except Per Share Amounts)                          2005           2004           2003
----------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>            <C>            <C>
Earnings for common stock                                                $  388.0       $  458.1       $  380.9
Houston Exploration dilution                                                    -              -           (0.3)
Preferred stock dividend                                                        -              -            0.5
----------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted                                     $  388.0       $  458.1       $  381.1
----------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000)                                 169,940        160,294        158,256
Add dilutive securities:
Options                                                                       861            983            755
Convertible preferred stock                                                     -              -            221
----------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution             170,801        161,277        159,232
----------------------------------------------------------------------------------------------------------------
Basic earnings per share                                                 $   2.28       $   2.86       $   2.41
----------------------------------------------------------------------------------------------------------------
Diluted earnings per share                                               $   2.27       $   2.84       $   2.39
----------------------------------------------------------------------------------------------------------------
</TABLE>


                                      115
<PAGE>


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 3.7 million of these shares were available
for issuance at December 31, 2005.  Under a separate plan,  Houston  Exploration
had issued stock options to its key 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
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 Millions of Dollars, Except Per Share Amounts)                                 2005           2004           2003
------------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>            <C>             <C>
Earnings available for common stock:
As reported                                                                      $ 388.0        $ 458.1         $ 380.9
     Add: recorded stock-based compensation expense, net of tax                      7.0            9.1             3.7
     Deduct: total stock-based compensation expense, net of tax                     (8.9)         (12.4)           (9.4)
------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings                                                               $ 386.1        $ 454.8         $ 375.2
------------------------------------------------------------------------------------------------------------------------
Earnings per share:
     Basic - as reported                                                         $  2.28        $  2.86         $  2.41
     Basic - pro-forma                                                           $  2.27        $  2.84         $  2.37

     Diluted - as reported                                                       $  2.27        $  2.84         $  2.39
     Diluted - pro-forma                                                         $  2.26        $  2.82         $  2.36
------------------------------------------------------------------------------------------------------------------------
</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:

--------------------------------------------------------------------------------
                                             Year Ended December 31,
                                     2005                2004              2003
--------------------------------------------------------------------------------
Fair value of grants issued     $    6.15          $    5.47           $  4.26
Dividend yield                       4.64%              4.74%             5.49%
Expected volatility                 22.63%             23.48%            24.26%
Risk free rate                       4.10%              3.22%             3.16%
Expected lives                   6.4 years          6.5 years           6 years
Exercise price                  $    39.25         $    37.54          $  32.40
--------------------------------------------------------------------------------


                                      116
<PAGE>


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,
                                                 2005                              2004                              2003
------------------------------------------------------------------------------------------------------------------------------------
                                                         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   10,540,946          $ 32.61        10,320,743          $ 31.39       9,524,900         $ 30.74
Granted during the year               1,451,650          $ 39.25         1,602,850          $ 37.54       1,650,450         $ 32.40
Exercised                            (1,400,190)         $ 30.65        (1,150,464)         $ 28.05        (664,902)        $ 23.64
Forfeited                              (149,351)         $ 36.32          (232,183)         $ 35.18        (189,705)        $ 34.63
------------------------------------------------------------------------------------------------------------------------------------
Outstanding at end of period         10,443,055          $ 33.74        10,540,946          $ 32.61      10,320,743         $ 31.39
------------------------------------------------------------------------------------------------------------------------------------
Exercisable at end of period          5,673,084          $ 31.55         5,523,259          $ 30.39       5,365,545         $ 28.76
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Remaining                             Weighted Average                                             Weighted Average     Range of
Contractual  Options Outstanding at       Exercise          Range of        Options Exercisable        Exercise         Exercise
  Life         December 31, 2005            Price         Exercise Price    at December 31, 2005        Price            Price
------------------------------------------------------------------------------------------------------------------------------------
<S>               <C>                       <C>           <C>                  <C>                      <C>         <C>
 1 years              148,000              $ 30.50            30.50               148,000              $ 30.50          30.50
 2 years              230,410              $ 32.54       $ 19.15 - 32.63          230,410              $ 32.54     $ 19.15 - 32.63
 3 years              844,625              $ 27.96       $ 24.73 - 29.38          844,625              $ 27.96     $ 24.73 - 29.38
 4 years              392,848              $ 26.97       $ 21.99 - 27.06          392,847              $ 26.97     $ 21.99 - 27.06
 5 years              998,887              $ 22.68       $ 22.50 - 32.76          998,887              $ 22.68     $ 22.50 - 32.76
 6 years            1,657,075              $ 39.50           $39.50             1,313,025              $ 39.50         $39.50
 7 years            1,944,811              $ 32.66           $32.66             1,054,195              $ 32.66         $32.66
 8 years            1,286,493              $ 32.40           $32.40               415,856              $ 32.40         $32.40
 9 years            1,502,756              $ 37.54           $37.54               275,239              $ 37.54         $37.54
 10 years           1,437,150              $ 39.25           $39.25                     -              $ 39.25         $39.25
------------------------------------------------------------------------------------------------------------------------------------
                   10,443,055                                                   5,673,084
------------------------------------------------------------------------------------------------------------------------------------
</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.  These
performance shares are measured over a three year period by comparing  KeySpan's
cumulative  total  shareholder  return  to the S&P  Utilities  Group.  The award
"cliff" vests after each 3 year period.

During 2005, it became  apparent to management that the 2003  performance  share
award would not be achieved  and the 2004  performance  share award would not be
achieved at the level of expense  being  recorded.  Since these  awards meet the
definition  of a  performance  condition  not achieved  under SFAS 123,  KeySpan
reversed the  previously  recognized  expense for the 2003 award and one half of
previously recognized expense for the 2004 award amounting to $3.8 million ($2.5
million after tax). For the 2005 award,  it is too early to predict  whether the
performance  condition  will be  achieved  and  therefore  none  of the  expense
recorded to date for the 2005 performance share award has been reversed.


                                      117
<PAGE>


In  December  2004,  the FASB  issued  SFAS  123R  "Share-Based  Payment"  which
superseded  SFAS 123. The  effective  date of SFAS 123R is the first  quarter of
2006.  Under this standard,  we will be prohibited from reversing any previously
recorded expense for the portion of the 2004 and 2005  performance  share awards
currently deemed  attainable.  This is due to the fact that the condition of our
current  performance share awards will be viewed as market conditions under SFAS
123R.

O.  Recent Accounting Pronouncements

On July 14, 2005, the Financial  Accounting  Standards  Board ("FASB") issued an
Exposure Draft  "Accounting for Uncertain Tax  Positions,"  that would interpret
SFAS 109,  "Accounting  for Income  Taxes."  This  proposal  seeks to reduce the
diversity in practice  associated  with certain  aspects of the  recognition and
measurement  requirements related to accounting for income taxes.  Specifically,
the proposal  would  require that a tax  position  meet a "probable  recognition
threshold"  for the benefit of an uncertain tax position to be recognized in the
financial  statements.  The proposal would require  recognition in the financial
statements  of the best  estimate of the effect of a tax  position  only if that
position is  probable  of being  sustained  on audit by the  appropriate  taxing
authorities, based solely on the technical merits of the position.

The proposed  effective date has been delayed until the first fiscal year ending
after January 1, 2007. KeySpan is currently  evaluating this Exposure Draft, and
at  this  time  cannot  determine  the  impact,   if  any,  that  the  potential
requirements  of this  Exposure  Draft may have on its  results  of  operations,
financial position or cash flows.

In March 2005, the FASB issued FASB Interpretation No. 47 ("FIN 47") "Accounting
for  Conditional  Asset  Retirement  Obligations  - an  interpretation  of  FASB
Statement No. 143." FIN 47 clarifies that the term conditional  asset retirement
obligation  as  used  in  SFAS  No.  143   "Accounting   for  Asset   Retirement
Obligations",  refers  to a legal  obligation  to  perform  an asset  retirement
activity in which the timing and/or method of settlement  are  conditional  on a
future  event  that may or may not be within  the  control  of the  entity.  The
obligation to perform the asset retirement activity is unconditional even though
uncertainty exists about the timing and/or method of settlement. Accordingly, an
entity is required to recognize a liability  for the fair value of a conditional
asset retirement obligation if the fair value of the liability can be reasonably
estimated.  Uncertainty  about  the  timing  and/or  method of  settlement  of a
conditional asset retirement  obligation should be factored into the measurement
of the liability when sufficient  information  exists. An entity shall recognize
the  cumulative  effect of initially  applying FIN 47 as a change in  accounting
principle.  KeySpan implemented FIN 47 in December 2005. See Note 1 Item P below
and Note 7 "Contractual Obligations, Financial Guarantees and Contingencies" for
further information on FIN 47.

In 2004,  the 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  clarified the  accounting  and
disclosure  requirements  for employers with  postretirement  benefit plans that
have been affected by the passage of the Medicare  Prescription Drug Improvement
and  Modernization  Act of 2003 (the "Medicare 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.

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 2004 and  determined  that the savings  associated
with  the  Medicare  Act  reduced   KeySpan's   retiree  health  care  costs  by
approximately  $10  million in 2004.  However,  KEDLI and Boston Gas Company are


                                      118
<PAGE>


subject to certain deferral  accounting  requirements  mandated by the NYPSC and
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 Medicare 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 Medicare Act had
no immediate impact on KeySpan's cash flow.

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. KeySpan reviewed
the new  provisions  and believes that the new guidance will not have a material
impact on its 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 SFAS 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 SFAS 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 SFAS 123; and  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
SFAS 123's  guidance in several  areas.  The effective date of this Statement is
the beginning of the first fiscal year  beginning  after June 15, 2005.  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 believes that implementation of this Statement will not
have a material impact on its results of operations or financial position and no
impact on its cash flows.

P.       Impact of Cumulative Effect of Change in Accounting Principles

As previously  discussed,  KeySpan  implemented FIN 47,  effective  December 31,
2005.  FIN 47 required  KeySpan to record a liability  and  corresponding  asset
representing  the present  value of  conditional  asset  retirement  obligations
associated  with the retirement of tangible,  long-lived  assets on the date the
obligations were incurred.  At year-end,  we recorded a $45.6 million  liability
and  corresponding  asset  representing  the present value of conditional  asset
retirement  obligations  associated with the retirement of tangible,  long-lived
assets on the date the obligations were incurred.  For the $45.6 million initial
asset recorded,  approximately  $4.3 million  represents  asset retirement costs
that  have  been  deferred  on  the  Consolidated  Balance  Sheet  and  will  be
depreciated over the remaining life of the underlying  associated  assets lives.


                                      119
<PAGE>


The remaining $41.3 million  represented  cumulative  accretion and depreciation
expense  associated  with the  liability  and asset  from the dates the  various
obligations would have been recorded had this  Interpretation  been in effect at
the time the obligations were incurred.

Of the $41.3 million recorded,  $11.3 million ($6.6 million,  net of taxes), was
recorded as a cumulative  change in  accounting  principle  on the  Consolidated
Statement of Income.  The remaining  $30.0 million was  attributable  to the Gas
Distribution  segment  and was  recorded  as a  reduction  to the  removal  cost
recovered.  For asset retirement costs incurred in the Gas Distribution segment,
KeySpan is recovering these costs from utility  customers and has been expensing
a like amount through its depreciation  expense.  A portion of this depreciation
expense represents  removal costs not yet incurred.  The $30 million recorded to
the removal cost  recovered is for purposes of  reclassifying  a portion of this
reserve  to  the  asset  retirement   obligation.   (See  Note  7,  "Contractual
Obligations,   Financial   Guarantees  and   Contingencies  -  Asset  Retirement
Obligations" for further details.)

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 FASB  Interpretation  No. 46 ("FIN 46").
This pronouncement required KeySpan to consolidate its variable interest entity,
which had a fair market  value of $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,  cumulative  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.)


                                      120
<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 Millions of Dollars, Except Per Share Amounts)                                   2005               2004               2003
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>                 <C>                <C>
Earnings for common stock                                                          $ 388.0             $ 458.1            $ 380.9
Add back: Cumulative effect of a change in accounting principle                        6.6                   -               37.4
Earnings for common stock before cumulative effect of a change
 in accounting principle:
As reported                                                                          394.6               458.1              418.3
     Less: FIN 47 Accretion expense, net of taxes                                     (0.5)               (0.4)              (0.4)
     Add: FIN 47 Depreciation expense, net of taxes                                   (0.2)               (0.2)              (0.1)
     Less: FIN 46  Depreciation expense, net of taxes                                    -                   -               (9.5)
----------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings                                                                 $ 393.9             $ 457.5            $ 408.3
----------------------------------------------------------------------------------------------------------------------------------

Earnings per share before cumulative change in accounting principle:
     Basic - as reported                                                            $ 2.32              $ 2.86             $ 2.64
     Basic - pro-forma                                                              $ 2.32              $ 2.85             $ 2.58

     Diluted - as reported                                                          $ 2.31              $ 2.84             $ 2.62
     Diluted - pro-forma                                                            $ 2.31              $ 2.84             $ 2.56
----------------------------------------------------------------------------------------------------------------------------------

Earnings per share for common stock:
     Basic - as reported                                                            $ 2.28              $ 2.86             $ 2.41
     Basic - pro-forma                                                              $ 2.32              $ 2.85             $ 2.58

     Diluted - as reported                                                          $ 2.27              $ 2.84             $ 2.39
     Diluted - pro-forma                                                            $ 2.31              $ 2.84             $ 2.56
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

In addition to the above disclosure, FIN 47 requires disclosure of the pro-forma
impact of the liability for the asset retirement obligation for the beginning of
the earliest  year  presented  and at the end of all years  presented as if this
Interpretation  had been applied during all periods effected.  The disclosure is
as follows:

--------------------------------------------------------------------------------
(In Millions of Dollars)
DECEMBER 31,                                       2005                   2004
--------------------------------------------------------------------------------
Asset retirement obligation - January 1           $ 44.9                 $ 42.5
Accretion                                            2.5                    2.4
--------------------------------------------------------------------------------
Asset retirement obligation - December 31         $ 47.4                 $ 44.9

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

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 Millions of Dollars)                                         2005             2004
----------------------------------------------------------------------------------------
<S>                                                             <C>              <C>
Foreign currency translation adjustments                       $     -          $   5.0
Unrealized (losses) on marketable securities                      (0.9)            (0.4)
Accrued unfunded pension obligation                              (63.5)           (59.8)
Unrealized (losses) gain on derivative financial instruments     (10.4)             0.9
----------------------------------------------------------------------------------------
Accumulated other comprehensive income                         $ (74.8)         $ (54.3)
----------------------------------------------------------------------------------------
</TABLE>


                                      121
<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 one to seven years and
power purchase  agreements  having  remaining  terms that range from seven to 21
years. On February 1, 2006, KeySpan and LIPA agreed to extend, amend and restate
these  contractual  arrangements.  (See Note 11,  "2006 LIPA  Settlement"  for a
further  discussion of these  agreements.)  The Electric  Services  segment also
includes  subsidiaries  that  own  or  lease  and  operate  the  2,200  megawatt
Ravenswood  Facility located in Queens,  New York, and the 250 MW combined-cycle
Ravenswood  Expansion.  Collectively  the  Ravenswood  Facility  and  Ravenswood
Expansion are referred to as the  "Ravenswood  Generating  Station".  All of the
energy,  capacity and ancillary  services  related to the Ravenswood  Generating
Station are sold to the NYISO energy  markets.  To finance the  purchase  and/or
construction of the Ravenswood Generating Station,  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
services to customers located  primarily within the Northeastern  United States.
Subsidiaries in this segment provide residential and small commercial  customers
with  service  and  maintenance  of energy  systems and  appliances,  as well as
operation  and  maintenance,  design,  engineering,  consulting  and fiber optic
services to commercial, institutional and industrial customers.

In  January  and  February  of 2005,  KeySpan  sold its  mechanical  contracting
subsidiaries.  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,  including approximately $5 million to be paid within
a three year period.  In addition,  KeySpan retained a portion of its previously
incurred surety indemnity support obligations related to certain performance and
payment bonds issued for the benefit of KeySpan's former  subsidiaries  prior to
closing. In June 2005, the balance to be paid over a three year period was fully
collected on a present value basis and a significant  portion of the performance
bonds were replaced without any remaining indemnification obligation on the part


                                      122
<PAGE>


of KeySpan.  The current  estimated cost to complete  projects  supported by the
remaining indemnity obligations associated with the January 2005 transactions is
approximately $0.2 million.  The buyers have agreed to complete the projects for
which such indemnity obligations were incurred and to indemnify and hold KeySpan
harmless with respect to its liabilities in connection with such bonds.

In connection  with the February 2005  transaction,  KeySpan paid or contributed
approximately  $26  million to a 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 surety 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 December 31,
2005, the total cost to complete such remaining  bonded projects is estimated to
be approximately  $40 million.  The  aforementioned  guarantees are reflected in
Note  7  "Contractual  Obligations,  Financial  Guarantees  and  Contingencies."
KeySpan's  former  subsidiary has also agreed to complete the projects for which
such indemnity obligations were incurred and indemnify and hold KeySpan harmless
with respect to any liabilities in connection with such bonds.

In  the  fourth  quarter  of  2004,   KeySpan's  investment  in  its  mechanical
contracting  subsidiaries  was  written-down to an estimated fair value.  During
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 10 "Energy Services - Discontinued
Operations" for additional  details  regarding these charges.)  During the first
six months of 2005,  operating losses were incurred through the dates of sale of
these  companies of $4.1 million  after-tax,  including but not limited to costs
incurred for employee related benefits.  Partially offsetting these losses was a
gain of $2.3 million  associated with the related  divestitures,  reflecting the
difference  between the fair value  estimates  and the  financial  impact of the
actual sale transactions.  The net income impact of the operating losses and the
disposal  gain was a loss of $1.8  million,  or $0.01 per  share for the  twelve
months ended December 31, 2005.

The Energy  Investments  segment  consists of our gas exploration and production
investments,  as well as  certain  other  domestic  energy-related  investments.
KeySpan's gas exploration  and production  activities  include our  wholly-owned
subsidiaries  Seneca  Upshur  Petroleum,  Inc.   ("Seneca-Upshur")  and  KeySpan
Exploration  and  Production,  LLC  ("KeySpan  Exploration").  Seneca-Upshur  is
engaged in gas exploration and production activities primarily in West Virginia.
KeySpan  Exploration is engaged in a joint venture with The Houston  Exploration
Company ("Houston Exploration"),  an independent natural gas and oil exploration
company located in Houston, Texas.

During  the  first  five  months of 2004,  our gas  exploration  and  production
investments  also  included a 55% equity  interest in Houston  Exploration,  the
operations of which were fully consolidated in KeySpan's  Consolidated Financial
Statements.  On June 2, 2004,  KeySpan  exchanged  10.8 million shares of common
stock of Houston Exploration for 100% of the stock of Seneca-Upshur,  previously


                                      123
<PAGE>


a wholly owned subsidiary of Houston  Exploration.  This transaction reduced our
interest in Houston  Exploration  from 55% to the then  current  level of 23.5%.
Effective  June 1,  2004,  Houston  Exploration's  earnings  and  our  ownership
interest  in Houston  Exploration  were  accounted  for on the equity  method of
accounting.  This  transaction  resulted in a gain to KeySpan of $150.1 million.
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 in fiscal  years 2004 and 2003,  were $268.1  million,  and
$495.3 million, respectively.  Houston Exploration's operating income, including
KeySpan's  share of equity  earnings,  was $138.5  million and $196.3 million in
fiscal years 2004 and 2003, respectively.

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.
The per share gain on this transaction was $0.12.

The  Energy  Investments  segment  is  also  engaged  in  pipeline   development
activities.  KeySpan and Duke Energy  Corporation each own a 50% interest in the
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, KeySpan has a 21%
interest in the Millennium Pipeline project which is expected to transport up to
525,000 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.   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.

Through its wholly owned  subsidiary,  KeySpan LNG, LP, KeySpan owns a liquefied
natural gas storage and receiving  facility in  Providence,  Rhode  Island,  the
operations of which are fully consolidated.

During the first quarter of 2004, we also had an  approximate  61% investment in
certain  midstream  natural gas assets in Western Canada through  KeySpan Energy
Canada  Partnership  ("KeySpan  Canada").  These assets  included 14  processing
plants and associated gathering systems that produced  approximately 1.5 BCFe of
natural gas daily and  provided  associated  natural gas liquids  fractionation.


                                      124
<PAGE>


These  operations were fully  consolidated in KeySpan's  Consolidated  Financial
Statements.  On April 1, 2004,  KeySpan and KeySpan  Facilities Income Fund (the
"Fund"), which previously owned a 39.09% interest in KeySpan Canada, consummated
a  transaction  whereby  the  Fund  sold  15.617  million  units of the Fund and
acquired an additional  35.91%  interest in KeySpan  Canada from  KeySpan.  As a
result of this transaction,  KeySpan's  ownership of KeySpan Canada decreased to
25%. KeySpan recorded a gain of $22.8 million ($10.1 million after-tax, or $0.06
per  share) at the time of this  transaction.  Effective  April 1, 2004  KeySpan
Canada's  earnings and our ownership  interest in KeySpan  Canada were accounted
for on the equity method 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 in fiscal years 2004 and 2003,  were $25.2 million and $90.3
million,  respectively.  KeySpan Canada's operating income,  including KeySpan's
share of equity earnings, was $16.5 million and $29.7 million, 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.  Additionally,  we sold our 20% interest in
Taylor NGL LP that owns 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 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, or $0.22 per share.

In the  first  quarter  of  2005,  KeySpan  sold  its 50%  interest  in  Premier
Transmission  Limited  ("Premier"),  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  Public  Limited  Company  ("PTFPL"),  pursuant  to  which  all of the
outstanding  shares of Premier were to be purchased by PTFPL. On March 18, 2005,
the sale was  completed  and  generated  cash  proceeds of  approximately  $48.1
million.  In the fourth  quarter of 2004,  KeySpan  recorded a pre-tax  non-cash
impairment  charge  of $26.5  million  reflecting  the  difference  between  the
anticipated  cash  proceeds  from the sale of Premier  compared to its  carrying
value.  The final sale of Premier  resulted  in a pre-tax  gain of $4.1  million
reflecting the difference from earlier estimates;  this gain was recorded in the
first quarter of 2005.


                                      125
<PAGE>


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.  For fiscal years 2004 and 2003,  the
operating  data of  Houston  Exploration  has  been  separately  displayed.  The
reportable segment information is as follows:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                   Gas         Electric      Energy         Other
(In Millions of Dollars)                      Distribution     Services     Services     Investments    Eliminations    Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2005
<S>                                             <C>            <C>           <C>           <C>             <C>           <C>
Unaffiliated revenue                             5,390.1        2,042.7       191.2          38.0               -           7,662.0
Intersegment revenue                                   -            4.6        10.8           5.0           (20.4)                -
Depreciation, depletion and amortization           277.0           91.7         7.6           6.8            13.4             396.5
Gain on sales of property                            0.1            1.2           -           0.1             0.2               1.6
Income from equity investments                         -              -           -          15.1               -              15.1
Operating income                                   565.7          342.3        (2.7)         20.6           (18.1)            907.8
Interest income                                      0.9            0.8         0.2           2.8             7.6              12.3
Interest charges                                   178.2           71.7        18.4           1.8            (0.8)            269.3
Total assets                                    10,052.5        2,348.0       199.0         341.9           871.2          13,812.6
Equity method investments                              -              -           -         106.7               -             106.7
Construction expenditures                          410.3           88.8         7.4          23.6             9.4             539.5
------------------------------------------------------------------------------------------------------------------------------------
</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 $2.0 billion for the year
ended  December  31,  2005  represents  approximately  26% of  our  consolidated
revenues during that period.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                       Gas           Electric    Energy        Houston       Other
(In Millions of Dollars)           Distribution      Services   Services     Exploration   Investments  Eliminations    Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
<S>                                  <C>             <C>         <C>           <C>          <C>            <C>            <C>
Unaffiliated revenue                  4,407.3         1,738.7     182.4         268.1         54.0                -         6,650.5
Intersegment revenue                        -               -      11.5             -          4.9            (16.4)              -
Depreciation, depletion and
 amortization                           276.5            88.2       7.5         104.6         59.7             15.3           551.8
Gain on sales of property                   -             2.0         -             -          5.0                -             7.0
Income from equity investments              -               -         -          20.7         25.8                -            46.5
Operating income                        579.6           289.8     (48.3)        138.5        (33.8)             9.5           935.3
Interest income                           2.2             9.9         -           3.5          3.0             (9.2)            9.4
Interest charges                        176.8            72.9      19.4           3.5          3.9             54.8           331.3
Total assets                          8,908.8         2,144.3     246.6             -        701.3          1,363.1        13,364.1
Equity method investments                   -               -         -             -        107.1                -           107.1
Construction expenditures               414.5           150.3      13.7         146.5         13.7             11.6           750.3
------------------------------------------------------------------------------------------------------------------------------------
</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 $1.7 billion for the year
ended  December  31,  2004  represents  approximately  25% of  our  consolidated
revenues during that period.


                                      126
<PAGE>


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                          Gas         Electric    Energy      Houston         Other
(In Millions of Dollars)             Distribution     Services    Services   Exploration   Investments  Eliminations   Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
<S>                                     <C>           <C>         <C>          <C>            <C>            <C>          <C>
Unaffiliated revenue                     4,161.3       1,606.0     158.9          495.3        114.0              -         6,535.5
Intersegment revenue                           -           0.1       7.5              -          5.0          (12.6)              -
Depreciation, depletion and
 amortization                              259.9          67.2       7.1          204.1         19.1           14.3           571.7
Gain on sales of property                   15.1             -         -              -            -              -            15.1
Income from equity investments                 -             -         -              -         19.1            0.1            19.2
Operating income                           574.3         269.9     (33.0)         196.3         42.2           (2.1)        1,047.6
Interest income                              1.2           4.6       1.1              -          1.0           (2.2)            5.7
Interest charges                           203.7          44.2      15.8            8.5          7.5           28.0           307.7
Total assets                             8,457.5       2,511.1     407.5        1,530.9        915.4          817.8        14,640.2
Equity method investments                      -             -         -              -         97.0              -            97.0
Construction expenditures                  419.6         256.5       7.0          295.9         18.1           12.3         1,009.4
------------------------------------------------------------------------------------------------------------------------------------
</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 $1.5 billion for the year
ended  December  31,  2003  represents  approximately  22% 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:

------------------------------------------------------------------------
                                          Year Ended December 31,
(In Millions of Dollars)             2005          2004           2003
------------------------------------------------------------------------
Current income tax                 $ 206.6       $ 201.9        $ (99.8)
Deferred income tax                   32.7         123.6          381.1
------------------------------------------------------------------------
Total income tax                   $ 239.3       $ 325.5        $ 281.3
------------------------------------------------------------------------

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

--------------------------------------------------------------------------
                                                      December 31,
(In Millions of Dollars)                        2005               2004
--------------------------------------------------------------------------
Reserves not currently deductible          $     28.4        $      23.9
State income tax                                (20.6)             (19.0)
Property related differences                 (1,080.8)          (1,080.0)
Regulatory tax asset                            (24.5)             (21.4)
Property taxes                                  (84.1)             (99.1)
Employee benefits and compensation              (64.4)             (16.6)
Other items - net                                88.1               88.1
--------------------------------------------------------------------------
Net deferred tax liability                 $ (1,157.9)        $ (1,124.1)
--------------------------------------------------------------------------


                                      127
<PAGE>


KeySpan is currently in discussions with the Internal Revenue Service ("IRS") at
the Appeals  level with  regard to 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 years  ending  September  30, 1997  through
December 31, 1998. The primary issue relates to the valuation of the transferred
assets in the  KeySpan/LILCO  combination.  Additionally,  the IRS has  recently
commenced the  examination  of KeySpan's tax returns for the year ended 2002 and
2003.  At this time,  we cannot  predict  the result of these  audits.  However,
KeySpan has  evaluated  the  potential  outcomes  based on the issues raised and
progress of the  discussions  to date.  KeySpan  believes that it has adequately
provided for the additional tax, if any, which may result.

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 Millions of Dollars)                             2005              2004             2003
----------------------------------------------------------------------------------------------
<S>                                                 <C>             <C>                <C>
Computed at the statutory rate               $       223.3       $    329.1      $      247.6
Adjustments related to:
Tax credits                                           (1.4)            (2.2)                -
Removal costs                                         (2.9)            (0.6)             (6.6)
Accrual to return adjustments                          6.7            (10.7)              0.5
Sale of subsidiary stock                                 -            (22.5)                -
Minority interest in Houston Exploration                 -             12.9              20.0
State income tax, net of federal benefit              29.0             24.8              28.5
Contribution of land                                  (3.8)               -                 -
Dividends paid to employee benefit plan               (3.9)            (3.6)                -
Other items - net                                     (7.7)            (1.7)             (8.7)
----------------------------------------------------------------------------------------------
Total income tax                             $       239.3      $     325.5       $     281.3
----------------------------------------------------------------------------------------------
Effective income tax rate (1)                          38%              35%                40%
----------------------------------------------------------------------------------------------
</TABLE>
(1) Reflects both federal as well as state income taxes.

The  American  Jobs  Creation  Act of 2004,  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 2004 or
2005.  We  currently   estimate  that  KeySpan  has  repatriated   dividends  of
approximately  $9.5 million of earnings under this provision and received,  as a
result, a tax benefit of $2.8 million.

As of December 31, 2005 KeySpan has $285 million of state tax net operating loss
carryforwards which, if fully utilized at current rates, will yield tax credits
of approximately  $25 million.  These credits will expire between 2011 and 2022.

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.


                                      128
<PAGE>


The calculation of net periodic pension cost is as follows:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
                                                                Year Ended December 31,
(In Millions of Dollars)                                  2005           2004           2003
-------------------------------------------------------------------------------------------------
<S>                                                     <C>            <C>            <C>
Service cost, benefits earned during the period       $    56.5      $    52.9      $    47.5
Interest cost on projected benefit obligation             148.5          144.2          138.3
Expected return on plan assets                           (173.1)        (158.2)        (130.6)
Net amortization and deferral                              74.1           63.3           67.0
Special termination benefits                                2.2              -              -
-------------------------------------------------------------------------------------------------
Total pension cost                                    $   108.2      $   102.2      $   122.2
-------------------------------------------------------------------------------------------------
</TABLE>

The following  table sets forth the pension plans' funded status at December 31,
2005 and December 31, 2004.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
                                                                                  Year Ended December 31,
(In Millions of Dollars)                                                        2005                   2004
-------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>                     <C>
Change in benefit obligation:
Benefit obligation at beginning of period                                  $ (2,520.1)            $  (2,343.2)
Service cost                                                                    (56.6)                  (52.9)
Interest cost                                                                  (148.5)                 (144.2)
Amendments                                                                       (0.1)                   (2.3)
Actuarial loss                                                                 (117.9)                 (114.6)
Benefits paid                                                                   130.4                   137.1
Special termination benefits                                                     (2.2)                      -
-------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                                        $ (2,715.0)            $  (2,520.1)
-------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period                              2,028.9                 1,855.2
Actual return on plan assets                                                    166.7                   164.2
Employer contribution                                                           148.3                   146.6
Benefits paid                                                                  (130.4)                 (137.1)
-------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                                    2,213.5                 2,028.9
-------------------------------------------------------------------------------------------------------------
Funded status                                                                  (501.5)                 (491.2)
Unrecognized net loss from past experience different from that
 assumed and from changes in assumptions                                        672.1                   612.1
Unrecognized prior service cost                                                  48.2                    57.7
-------------------------------------------------------------------------------------------------------------
Net prepaid pension cost reflected on consolidated balance sheet           $    218.8             $     178.6
-------------------------------------------------------------------------------------------------------------
</TABLE>

-------------------------------------------------------------------------------
                                                   Year Ended December 31,
                                                2005         2004        2003
-------------------------------------------------------------------------------
Assumptions:
Obligation discount                             5.75%        6.00%       6.25%
Asset return                                    8.50%        8.50%       8.50%
Average annual increase in compensation         4.00%        4.00%       4.00%
-------------------------------------------------------------------------------


                                      129
<PAGE>


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

-------------------------------------------------
(In Millions of Dollars)         Pension Benefits
-------------------------------------------------

      2006                               $ 132.2
      2007                               $ 134.1
      2008                               $ 137.7
      2009                               $ 141.4
      2010                               $ 146.0
      Years 2011- 2015                   $ 839.3
-------------------------------------------------

Unfunded  Pension  Obligation:  At  December  31, 2005 the  accumulated  benefit
obligation was in excess of pension assets. As prescribed by SFAS 87 "Employers'
Accounting for  Pensions,"  KeySpan had a $257.3  million  minimum  liability at
December 31, 2005,  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
$41.2 million,  representing the amount of unrecognized prior service cost and a
debit to  accumulated  other  comprehensive  income of $97.8  million,  or $63.6
million  after-tax.  The  remaining  amount of $118.3  million was recorded as a
contractual  receivable  from LIPA of $103.8  million and a regulatory  asset of
$14.5  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. Boston Gas 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, 2005 the  projected  benefit  obligation,  accumulated  benefit
obligation and value of assets for plans with accumulated benefit obligations in
excess  of plan  assets  were  $1.4  billion,  $1.3  billion  and $997  million,
respectively.

At December 31, 2004, the accumulated  benefit  obligation was also in excess of
pension assets.  As a result,  we had a minimum  liability of $255.9 million,  a
long-term asset in deferred charges other of $49.7 million, 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.

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


                                      130
<PAGE>


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:

-------------------------------------------------------------------------------
                                                      Year Ended December 31,
(In Millions of Dollars)                            2005       2004     2003
-------------------------------------------------------------------------------
Service cost, benefits earned during the period   $  24.4     $ 19.7    $ 18.8
Interest cost on accumulated
   postretirement benefit obligation                 75.7       70.2      69.8
Expected return on plan assets                      (36.1)     (33.9)    (27.5)
Net amortization and deferral                        59.9       41.0      35.8
Special termination benefit                           1.7          -         -
-------------------------------------------------------------------------------
Other postretirement cost                         $ 125.6     $ 97.0    $ 96.9
-------------------------------------------------------------------------------

The following table sets forth the plans' funded status at December 31, 2005 and
December 31, 2004.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                                                                                             Year Ended December 31,
(In Millions of Dollars)                                                                     2005              2004
----------------------------------------------------------------------------------------------------------------------
<S>                                                                                      <C>                <C>
Change in benefit obligation:
Benefit obligation at beginning of period                                               $ (1,336.7)        $ (1,267.6)
Impact due to Medicare subsidy                                                                   -               60.6
Service cost                                                                                 (24.4)             (19.7)
Interest cost                                                                                (75.7)             (70.2)
Plan participants' contributions                                                              (3.4)              (1.9)
Amendments                                                                                     3.2               27.4
Actuarial (loss)                                                                             (38.3)            (119.9)
Benefits paid                                                                                 62.7               54.6
Special termination benefit                                                                   (1.7)                 -
----------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                                                       (1,414.3)          (1,336.7)
----------------------------------------------------------------------------------------------------------------------
Change in plan  assets:
Fair value of plan assets at beginning of period                                             464.0              438.4
Actual return on plan assets                                                                  29.1               38.8
Employer contribution                                                                         35.8               39.5
Plan participants' contributions                                                               3.4                1.9
Benefits paid                                                                                (62.7)             (54.6)
----------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                                                   469.6              464.0
----------------------------------------------------------------------------------------------------------------------
Funded status                                                                               (944.7)            (872.7)
Unrecognized net loss from past experience different from that assumed
 and from changes in assumptions                                                             557.5              576.8
Unrecognized prior service cost                                                              (97.5)            (106.5)
----------------------------------------------------------------------------------------------------------------------
Accrued postretirement cost reflected on consolidated balance sheet                     $   (484.7)        $   (402.4)
----------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      131
<PAGE>


<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------
                                                   Year Ended December 31,
                                              2005            2004          2003
-----------------------------------------------------------------------------------
<S>                                          <C>             <C>            <C>
Assumptions:
Obligation discount                           5.75%           6.00%          6.25%
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 9.5%  grading  down to 4.75%  over six  years,  and  4.75%  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, 2005 by
$173.1 million and the net periodic  health care expense by $14.9 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, 2005 by
$151.1 million and the net periodic health care expense by $12.6 million.

At December 31, 2005,  KeySpan had a contractual  receivable from LIPA of $297.4
million  representing the pension and other  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:

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

       2006                             $ 65.9                    $ 3.5
       2007                             $ 70.6                    $ 3.9
       2008                             $ 74.9                    $ 4.3
       2009                             $ 79.6                    $ 4.7
       2010                             $ 83.9                    $ 5.0
       Years 2011- 2015                $ 469.3                   $ 28.1
-------------------------------------------------------------------------------
**  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, 2005 and 2004, by asset category, for both the
pension and other postretirement benefit plans are as follows:


-----------------------------------------------------------------------------
                                   Pension                        OPEB
Asset Category                2005          2004           2005          2004
-----------------------------------------------------------------------------
Equity securities              65%           64%            70%          72%
Debt securities                27%           28%            23%          23%
Cash and equivalents            3%            3%             2%            -
Venture capital                 5%            5%             5%           5%
-----------------------------------------------------------------------------
Total                         100%          100%           100%         100%
-----------------------------------------------------------------------------


                                      132
<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 2006, KeySpan is expected to contribute approximately $90
million  to its  pension  plans  and  approximately  $30  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").  Eligible  employees  contributing  to the Plan may  receive  certain
employer  contributions  including matching  contributions and a 10% discount on
the  purchase of KeySpan  Common Stock in the Plan.  The matching  contributions
were in KeySpan's common stock until January 2006. The matching contributions as
now  determined  at the  election  of  KeySpan  employees.  For the years  ended
December 31, 2005, 2004 and 2003, we recorded an expense of $15.2 million, $14.7
million, and $11.2 million, respectively.

Note 5. Capital Stock

Common Stock:  Currently we have 450,000,000  shares of authorized common stock.
At December 31, 2005, we had 10.5 million shares,  or $303.9 million of treasury
stock outstanding. During 2005, we issued 1.4 million shares out of treasury for
the dividend  reinvestment  feature of our Investor Program,  the Employee Stock
Discount  Stock  Purchase  Plan,  the 401(k)  Plan and the  Long-Term  Incentive
Compensation Plan.

On May 16,  2005,  KeySpan  issued  12.1  million  shares  of common  stock,  in
association  with the MEDS Equity  Units  conversion,  at an  issuance  price of
$37.93 per share pursuant to the terms of the forward purchase contract. KeySpan
received proceeds of approximately $460 million from the equity conversion.  The
number of shares issued was dependent 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.  (See Note 6  "Long-Term  Debt and  Commercial  Paper" for further
details on the MEDS Equity Units.)

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.


                                      133
<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 May 2005, $55.3 million of 7.07% Series B preferred stock was redeemed on its
scheduled  redemption date.  Additionally,  also in May 2005, KeySpan called for
the optional  redemption of $19.7  million of 7.17% Series C of Preferred  Stock
due 2008. KeySpan no longer has preferred stock outstanding.

Note 6. Long-Term Debt And Commercial Paper

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,  2005 and 2004,  each of which is  guaranteed  by
KeySpan.

KeySpan  also had $1.96  billion of medium and long term  notes  outstanding  at
December 31, 2004 of which $950 million of these notes were  associated with the
acquisition  of  Eastern  and ENI.  These  notes  were  issued in two  series as
follows:  $700  million of 7.625% Notes due 2010 and $250 million of 8.00% Notes
due 2030.  The remaining  debt of  approximately  $1 billion had interest  rates
ranging from 4.65% to 9.75%.

During  2005,  KeySpan  redeemed  $500 million  6.15% Notes due 2006 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 $20.9 million  associated  with call  premiums and wrote-off  $1.3
million of previously deferred financing costs. Further, KeySpan accelerated the
amortization of approximately $11.2 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 on the Consolidated
Statement of Income. In addition,  during the first quarter of 2005, $15 million
of 8.87% notes of a KeySpan subsidiary were redeemed at maturity.

Further, in association with the MEDS Equity Units conversion, KeySpan converted
$460  million of MEDS Equity  Units into $467.2  million of medium and long term
bonds.  (For further  details on the MEDS Equity  Units see "MEDS Equity  Units"
below.) As a result of the  aforementioned  transactions,  at December  31, 2005
KeySpan had $2.4 billion of notes  outstanding  with interest rates ranging from
4.65% to 9.75% that mature in 2006-2035.

Gas Facilities  Revenue Bonds:  KEDNY can issue tax-exempt bonds through the New
York State Energy Research and Development Authority ("NYSERDA"). 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  ("GFRBs").  At
December 31, 2005, $640.5 million of GFRBs were  outstanding.  The interest rate
on the  variable  rate series due through  December 1, 2026 is reset  weekly and
ranged from 1.40% to 2.95% during the year ended  December  31,  2005,  at which
time the rate was 2.85%.


                                      134
<PAGE>


In November  2005,  KEDNY,  issued $137 million of tax-exempt  GFRBs through the
NYSERDA in the following  series:  (i) $82 million of 4.70% GFRB,  2005 Series A
(the "Series A Bonds");  and (ii) $55 million GFRB, 2005 Series B (the "Series B
Bonds").  The  interest  rate on the Series B bonds is re-set  every  seven days
through an auction  process and at December 31, 2005 the interest  rate on these
bonds was  3.15%.  KEDNY  used the  proceeds  from this  issuance  to redeem the
following three series:  (i) $41 million  Adjustable Rate GFRB Series 1989 A due
February 2024; (ii) $41 million  Adjustable Rate GFRB Series 1989 B due February
2024;  and (iii) $55  million  5.60% GFRB  Series  1993 C due June  2025.  KEDNY
incurred  $3.7 million in call premiums and  financing  fees,  all of which have
been deferred for future rate recovery.

In December 2005,  KEDNY  converted $50 million of fixed rate GFRB's (5.64% GFRB
Series D1 and D2 due 2026) into variable  rate debt.  The interest rate on these
bonds is reset,  through an auction  process,  every seven days. At December 31,
2005 the interest rate was 3.00%.

Promissory  Notes to LIPA: 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, 2005,  $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,
2005, 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  required us,
three years from the date of issuance of the MEDS Equity Units, May 16, 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 was 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%.

In 2005, KeySpan was required to remarket the note component of the Equity Units
between  February  2005 and May 2005 and  reset  the  interest  rate to the then
current market rate of interest;  however,  the reset interest rate could not be
set below 4.9%. In March 2005,  KeySpan  remarketed the note component of $394.9
million of the Equity Units at the reset  interest  rate of 4.9%  through  their
maturity date of May 2008. The balance of the notes ($65.1 million) were held by
the  original  MEDS  equity  holders  in  accordance  with  their  terms and not
remarketed.  KeySpan then  exchanged  $300 million of the  remarketed  notes for
$307.2 million of new 30 year notes bearing an interest rate of 5.8%. Therefore,
KeySpan now has $160 million of 4.9% notes  outstanding  with a maturity date of
May 2008 and $307.2  million of 5.8% notes  outstanding  with a maturity date of
April 2035 that are classified as Medium and Long Term Notes.

On May 16,  2005  KeySpan  issued 12.1  million  shares of common  stock,  at an
issuance  price of $37.93  per  share,  pursuant  to the terms of the  financial
purchase  contract  described above.  KeySpan received proceeds of approximately
$460  million  from the  equity  conversion.  The  number of shares  issued  was
dependent  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.


                                      135
<PAGE>


Industrial   Development  Revenue  Bonds:  At  December  31,  2005  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  Energy  Center  an
electric-generation   peaking   plant.   KeySpan  has   guaranteed  all  payment
obligations of these subsidiaries with regard to these bonds.

First  Mortgage  Bonds:  Colonial Gas Company had  outstanding  $95.0 million of
first  mortgage  bonds at  December  31,  2005.  These  bonds are secured by 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. At December 31, 2005, these bonds remain outstanding and have 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 NYSERDA.  At December 31, 2005, $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 2005 ranged from 1.40%
to 2.85%, through December 31, 2005, at which time the rate was 3.00%.

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 1.47% to 3.42% for the year ended  December 31,
2005, at which time the rate was 3.42%.

Ravenswood  Master Lease: We have an arrangement  with an unaffiliated  variable
interest  financing  entity  through which we lease a portion of the  Ravenswood
Facility.  We acquired the Ravenswood  Facility,  in part,  through the variable
interest entity, from the Consolidated Edison Company of New York ("Consolidated
Edison") on June 18, 1999 for approximately $597 million. In order to reduce the
initial  cash  requirements,  we entered  into a lease  agreement  (the  "Master
Lease")  with the  variable  interest  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
substantially  equal  to the  fair  market  value of the  leased  assets  at the
inception of the lease,  less  depreciation  since that date,  or  approximately
$322.8 million.  Under the terms of our 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.)


                                      136
<PAGE>


Commercial Paper and Revolving Credit  Agreements:  In June 2005, KeySpan closed
on a $920 million  revolving  credit  facility for five years due June 24, 2010,
which was syndicated among fifteen banks, and an amended $580 million  revolving
credit facility due June 24, 2009.  These  facilities  replaced an existing $660
million,  3-year facility due June 2006, and a 5-year $640 million  facility due
June  2009.  The two  credit  facilities,  which now total  $1.5  billion - $920
million for five years through 2010,  and $580 million for the amended  facility
through 2009, will continue to support  KeySpan's  commercial  paper program for
ongoing working capital needs.

The fees for the  facilities  are based on KeySpan's  current credit ratings and
are increased or decreased  based on a downgrading  or upgrading of our ratings.
The current  annual  facility  fee is 0.07% based on our credit  rating of A3 by
Moody's  Investor  Services and A by Standard & Poor's for each  facility.  Both
credit  facilities allow for KeySpan to borrow using several  different types of
loans;  specifically,  Eurodollar  loans, ABR loans, or competitively bid loans.
Eurodollar  loans are based on the Eurodollar rate plus a margin that is tied to
our applicable  credit  ratings.  ABR loans are based on the higher 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 utility 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 65% at the
last day of any fiscal quarter. Violation of these covenants 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.  At
December  31,  2005,  KeySpan's  consolidated  indebtedness  was  50.7%  of  its
consolidated capitalization and KeySpan was in compliance with all covenants.

Subject to certain conditions set forth in the credit facility,  KeySpan has the
right, at any time, to increase the commitments  under the $920 million facility
up to an additional $300 million. In addition,  KeySpan has the right to request
that the termination date be extended for an additional period of 365 days prior
to each  anniversary  of the  closing  date.  This  extension  option,  however,
requires the approval of lenders holding more than 50% of the total  commitments
to such  extension  request.  Under the  agreements,  KeySpan has the ability to
replace  non-consenting  lenders  with  other  pre-approved  banks or  financial
institutions.

At December 31,  2005,  we had cash and  temporary  cash  investments  of $124.5
million.  During 2005,  we repaid  $254.6  million of  commercial  paper and, at
December 31, 2005,  $657.6  million of  commercial  paper was  outstanding  at a
weighted  average  annualized  interest  rate of 4.38%.  At December  31,  2005,
KeySpan had the ability to issue up to an  additional  $842  million,  under its
commercial paper program.


                                      137
<PAGE>


Capital Leases:  Our subsidiaries  lease certain  facilities and equipment under
long-term  leases,  which expire on various  dates  through  2014.  The weighted
average interest rate on these obligations was 6.0%.

Debt Maturity: The following table reflects the maturity schedule for our debt
repayment requirements, including capitalized leases and related maturities, at
December 31, 2005:

-----------------------------------------------------------------------------
-----------------------------------------------------------------------------
                                   Long-Term        Capital
 (In Millions of Dollars)             Debt           Leases           Total
-----------------------------------------------------------------------------
 Repayments:
    2006                          $    12.0         $  1.0         $    13.0
    2007                                  -            1.1               1.1
    2008                              305.0            1.1             306.1
    2009                              412.3            1.2             413.5
    2010                            1,110.0            1.3           1,111.3
    Thereafter                      2,095.4            5.1           2,100.5
-----------------------------------------------------------------------------
                                  $ 3,934.7         $ 10.8         $ 3,945.5
-----------------------------------------------------------------------------

Note 7. Contractual Obligations, Financial Guarantees and Contingencies

Lease Obligations:  Lease costs included in operating expense were $76.5 million
in 2005 including, the lease of KeySpan's Brooklyn headquarters of $14.1million.
Further,  in  March  2005,  KeySpan  renegotiated  the  lease  of  the  Brooklyn
headquarters.  The original  agreement was to expire in 2012.  The current lease
will expire in 2025. Yearly lease expense is approximately $11.7 million. In May
2004 KeySpan  entered into a leveraged lease  financing  arrangement  associated
with  the  Ravenswood   Expansion.   The  yearly   operating  lease  expense  is
approximately  $17 million  per year.  (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, 2004 and 2003 were $67.7 million and
$82.1  million,  respectively.  As  previously  mentioned,  the Master  Lease is
consolidated and, as a result,  lease payments are 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 $100.6 million per year
over the next five years and $652.4  million,  in the  aggregate,  for all years
thereafter.  (See discussion below for further information  regarding the Master
Lease and the Ravenswood Expansion sale/leaseback transaction.)

Variable  Interest  Entity:  As mentioned,  KeySpan has an  arrangement  with an
unaffiliated variable interest financing 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 the variable interest 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  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, 2005 was $29.7 million.


                                      138
<PAGE>


The term of the  Master  Lease  extends  through  June 20,  2009.  On all future
semi-annual  payment dates,  we have the right to: (i) 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.

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
$322.8 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  $152
million over the next five years and $417  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:

On December 31, 2005,  KeySpan  implemented  FIN 47 "Accounting  for Conditional
Asset  Retirement  Obligations."  FIN 47 was  issued  to  clarify  that the term
conditional  asset  obligation used in SFAS 143 "Accounting for Asset Retirement
Obligations"  refers  to a legal  obligation  to  perform  an  asset  retirement
activity in which the timing and (or) method of settlement are  conditional on a
future  event  that  may or  may  not  be  within  the  control  of the  entity.
Previously, KeySpan adopted SFAS 143 on January 1, 2003. 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.


                                      139
<PAGE>


At December 31, the following asset  retirement  obligations are recorded on the
Consolidated Balance Sheet at their estimated present values:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
  (In Millions of Dollars)
  -------------------------------------------------------------------------------------------------------
  December 31,                                            2005               2004
  -------------------------------------------------------------------------------------------------------
 <S>                                             <C>              <C>                 <C>
  Asset Retirement Obligations
  Asbestos removal                               (i)             $  3.5              $   -
  Tanks removal and cleaning                     (ii)               6.9                  -
  Main -cutting, purging and capping             (iii)             30.6                  -
  Wells - plug and capping                       (iv)               0.2                  -
  KeySpan LNG tank demolition                    (v)                2.1                  -
  Waste water treatment pond removal             (vi)               1.4                  -
  Fiber network removal                          (vii)              0.8                  -
  Exploration wells-plug and capping             (viii)             1.9                1.9

  ------------------------------------------------------------------------------------------------------
  Total Asset Retirement Obligations                             $ 47.4              $ 1.9
  ------------------------------------------------------------------------------------------------------
</TABLE>



(i)       Asbestos-containing  materials  was deemed to exist in roof  flashing,
          floor tiles, pipe insulation and mechanical room insulation within our
          common facilities as well as in our older generation  plants.  KeySpan
          has a  legal  obligation  to  remove  asbestos  upon  either  a  major
          renovation or demolition.

(ii)      KeySpan has numerous  storage  tanks that  contain  among other things
          waste oil, #2 and #6 fuel oil, diesel fuel, multi chemicals, lube oil,
          kerosene,  ammonia,  and other waste contaminants.  All of these tanks
          are subject to cleaning and removal  requirements  prior to demolition
          and retirement if so specified by law or regulation.

(iii)     KeySpan  has a  legal  requirement  to cut  (disconnect  from  the gas
          distribution   system),   purge   (clean  of   natural   gas  and  PCB
          contaminants)  and cap gas  mains  within  its  gas  distribution  and
          transmission  system  when mains are  retired in place.  Gas mains are
          generally  abandoned in place when retired,  unless the main and other
          equipment  needs to be removed due to sewer or water system  rerouting
          or other  roadblock  work.  When such main and  equipment  are removed
          certain PCB test procedures must be employed.

(iv)      KeySpan owns  approximately 52% of an underground gas storage facility
          in western New York State. The facility  includes 39 gas injection and
          extraction wells.  There is a regulatory  obligation to close and seal
          the wells.

(v)       KeySpan owns a 600,000  gallon  barrel  Liquefied  Natural Gas ("LNG")
          tank and ancillary  facilities  located in  Providence,  RI under a 30
          year  contract  with  New  England  Gas  Company.  At  the  end of the
          contract,  the contract can be; (i) Extended;  or (ii) New England Gas
          Company can require KeySpan to


                                      140
<PAGE>


          dismantle and remove the LNG tank and ancillary  facilities  or; (iii)
          KeySpan can elect to dismantle  and remove the LNG tank and  ancillary
          facilities.  Since  we may or may not be  required  to  dismantle  and
          remove  the LNG tank  and  ancillary  facilities,  the  obligation  to
          perform was discounted to a 50% probability as allowed under FIN 47.

(vi)      KeySpan has several wastewater treatment ponds associated with certain
          of its power stations.  There are closure  requirements for wastewater
          treatment pond systems based on  regulations  promulgated by the State
          of New York which were effective May 11, 2003.

(vii)     KeySpan  Communications  has  portions  of  its  fiber  optic  network
          (underground  and above  ground)  that are required to be removed upon
          termination of various agreements.

(viii)    KeySpan  has a  regulatory  obligation  to close  and  seal the  wells
          primarily   associated   with  its  gas   exploration  and  production
          activities.

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, 2005, 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 Millions of Dollars)                                       Exposure       Dates
-----------------------------------------------------------------------------------------------
  <S>                                            <C>             <C>         <C>
   Guarantees for Subsidiaries
   Medium-Term Notes - KEDLI                     (i)            $   525.0     2008 - 2010
   Industrial Development Revenue Bonds          (ii)               128.3        2027
   Ravenswood - Master Lease                     (iii)              425.0        2009
   Ravenswood - Sale/leaseback                   (iv)               403.5        2019
   Surety Bonds                                  (v)                 76.0     2005 - 2008
   Commodity Guarantees and Other                (vi)                83.2     2005 - 2009
   Letters of Credit                             (vii)               73.0     2006 - 2010
-----------------------------------------------------------------------------------------------
                                                                $ 1,714.0
-----------------------------------------------------------------------------------------------
</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.


                                      141
<PAGE>


(iii)     KeySpan has  guaranteed  all payment and  performance  obligations  of
          KeySpan  Ravenswood,  LLC, the lessee under the Master Lease. The term
          extends  through June 20,  2009.  The Master  Lease is  classified  as
          $412.3 million long-term debt on the Consolidated Balance Sheet.

(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, including
          future  decommissioning costs. 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 being
          performed by certain current or former subsidiaries. In the event that
          the subsidiaries  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.  Although
          KeySpan  is not  guaranteeing  any new  bonds  for  any of the  former
          subsidiaries,  KeySpan's indemnity obligation supports the contractual
          obligation  of these former  subsidiaries.  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.
          At December 31, 2005, the total cost to complete such remaining bonded
          projects is estimated to be approximately $40.2 million.

(vi)      KeySpan has  guaranteed  commodity-related  payments for  subsidiaries
          within the Energy Services segment, as well as for 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, 2005.

(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.

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


                                      142
<PAGE>



Fixed Charges Under Firm Contracts:  Our utility subsidiaries and the Ravenswood
Generation Station 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  $492.7 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 were named
as defendants in 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 on  February 9, 2005,
also  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.  On January 3, 2006, the parties  entered into a
settlement  agreement  to settle the action for a nominal  sum of  $250,000  for
plaintiff's  counsel  fees  and  for  KeySpan  to  implement  certain  corporate
governance practices. The settlement agreement is subject to court approval, the
timing of which cannot be predicted.  While KeySpan  denies any  wrongdoing,  we
believe the settlement is in the best interest of KeySpan and its shareholders.

KeySpan  subsidiaries,  along with  several  other  parties,  have been named as
defendants in numerous  proceedings filed by plaintiffs claiming various degrees
of injury from asbestos  exposure at  generating  facilities  formerly  owned by
LILCO and others.  In connection with the May 1998  transaction with LIPA, costs
incurred by KeySpan for  liabilities  for  asbestos  exposure  arising  from the
activities  of  the  generating   facilities   previously  owned  by  LILCO  are
recoverable from LIPA through the 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 1998 and 2006 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.  KeySpan and LIPA have entered
into agreements to extend,  amend, and restate these  contractual  arrangements.
See Note 11 "2006 LIPA Settlement" for a further discussion these agreements.


                                      143
<PAGE>


LIPA  completed  its  strategic  review  initiative  that it had  undertaken  in
connection  with among other reasons,  its option under the Generation  Purchase
Rights  Agreement  As part of its review,  LIPA  engaged a team of advisors  and
consultants,  held public hearings and explored its strategic options, including
continuing its existing operations,  municipalizing,  privatizing, selling some,
but not all of its  assets,  becoming  a  regulator  of rates and  services,  or
merging with one or more  utilities.  Upon  completion of its strategic  review,
LIPA determined that it would continue its existing  operations,  as part of its
settlement with KeySpan and the  renegotiated  2006 LIPA Agreements noted above.
The 2006 LIPA  Agreements  are subject to  governmental  approvals,  and if such
governmental  approvals  are not  received  then LIPA may revisit its  strategic
review alternatives.

Environmental Matters

Air: Our generating  facilities are located within a Clean Air Act ("CAA") ozone
non-attainment and PM 2.5 (fine particulate matter) non-attainment area, and are
subject to Phase I, II and III NOx reduction requirements  established under the
Ozone  Transport   Commission   memorandum  of  understanding   and  forthcoming
requirements  under the Clean Air Interstate  Rule ("CAIR")  designed to address
both ozone and particulate  matter.  Our previous  investments in low NOx boiler
combustion  modifications,  the use of natural  gas firing  systems at our steam
electric generating  stations,  and the compliance  flexibility  available under
these cap and trade  programs,  have  enabled  KeySpan to achieve  the  emission
reductions  required.  KeySpan is developing its compliance strategy in response
to the  implementation  of the CAIR  rule,  which  is  expected  in 2009.  Since
detailed  requirements  under the CAIR rule have not yet been fully articulated,
it is not possible to definitively  estimate  capital  expenditures  that may be
required to meet these regulatory mandates. Although, it is anticipated that NOx
control  equipment may be required at one or more of the  KeySpan's  Long Island
facilities  at a cost between $25 to $35 million,  such amounts are  recoverable
from LIPA pursuant to the 1998 PSA or if applicable, the 2006 PSA.

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  and are engaged in  discussions  with the DEC
regarding the nature of capital upgrades or other mitigation  measures necessary
to satisfy these evolving  regulatory  requirements.  It is not possible at this
time to predict the extent of such capital  investments  but these  upgrades are
expected to cost up to $60 million,  however,  such amounts are recoverable from
LIPA  pursuant to the 1998 PSA or if  applicable,  the 2006 PSA. The  Ravenswood
Generating Station may also require upgrades at a cost of up to $15 million. The
actual  expenditures will depend upon the outcome of the ongoing studies and the
subsequent  determination  by the DEC of how 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  During  2005,  KeySpan
undertook an extensive review of all its current and former  properties that are
or may be  subject  to  environmental  cleanup  activities.  As a result of this
study, we adjusted reserve balances for estimated manufactured gas plant ("MGP")
related environmental cleanup activities.  Through various rate orders issued by
the  NYPSC,  MADTE  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.


                                      144
<PAGE>


New York Sites:  Within the State of New York we have  identified  43 historical
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 and one waterway.  In March 2005,  KeySpan  withdrew its previously  filed
applications  under the DEC's Brownfield  Cleanup Program ("BCP") because of the
uncertainty  associated  with  contribution  suits  which  we may  need to bring
against other parties who impacted these sites for their share of remedial cost.
As a result of the December  2004 Cooper  Industries  v. Aviall  Services,  Inc.
decision by the United  States  Supreme  Court and the emerging  case law in New
York, KeySpan continues to evaluate how to proceed with respect to participation
in the BCP or alternative DEC remediation programs.

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 $60.9 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 $51.8 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 $355.3 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.  Expenditures
incurred to date by us with respect to these MGP-related activities total $112.7
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,  2005,  we have  reflected a regulatory  asset of $388.0
million for our KEDNY/KEDLI MGP sites. 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


                                      145
<PAGE>


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 $1.7  million,  which amount has been
accrued by us. Expenditures incurred to date total $3.3 million.

New England Sites: Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 74 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 64 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 $15.5 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 upon changing technologies and regulatory standards,  selected
end  use  for  each  site,  and  actual  environmental  conditions  encountered.
Expenditures  incurred since November 8, 2000, the date KeySpan acquired Eastern
Enterprises, with respect to these MGP-related activities total $27.9 million.

In 2004, 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 $5.0 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 $31.5 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
upon changing technologies and regulatory  standards,  selected end use for each
site, and actual environmental  conditions  encountered.  Expenditures  incurred
since November 8, 2000, with respect to these MGP-related activities total $17.0
million.


                                      146
<PAGE>


By rate  orders,  the MADTE  and the  NHPUC  provide  for the  recovery  of site
investigation and remediation costs and,  accordingly,  at December 31, 2005, we
have reflected a regulatory  asset of $66.7 million for the KEDNE MGP sites.  As
previously mentioned, Colonial Gas Company and Essex Gas Company are not subject
to the  provisions of SFAS 71 and therefore  have recorded no regulatory  asset.
However,  rate 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,  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  entered  into a  cost-sharing  agreement  under which each  company
agreed to pay one-third of the costs of compliance with the consent order, while
preserving  any claims  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
sought a judicial  determination  on the allocation of liability for the Everett
Facility.  A  confidential  settlement  agreement has been executed on favorable
terms to KeySpan and the Beazer lawsuit has been discontinued.

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.   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
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.


                                      147
<PAGE>


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.  On November 14,  2005,  the trial
commenced  on the  declaratory  judgment  action of Boston Gas  against  Century
Indemnity for insurance coverage for the costs incurred in the investigation and
remediation  at the former  Boston Gas Everett MGP site and on December 6, 2005,
the jury  returned  a verdict  in favor of  KeySpan.  KeySpan  anticipates  that
Century  Indemnity  will appeal this verdict.  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.  On October 5, 2004,  EnergyNorth's  case
against the London  Market  Insurers for the costs  incurred  investigating  and
remediating  the  former MGP site in  Laconia  went to trial and on October  25,
2004,  the  jury  returned  a  verdict  in favor of  EnergyNorth,  finding  that
EnergyNorth was entitled to recover against London Market Insurers.  The precise
amount of the  recovery  will depend on the  allocation  calculations  which the
court has yet to apply to this case. We anticipate  that London Market  Insurers
will appeal this  verdict.  On February  15,  2005,  the trial of  EnergyNorth's
coverage  action  for the  Dover  MGP site  began  against  the  only  remaining
defendant,  Century Indemnity (all other carriers settled prior to trial) and at
the   conclusion  of  the  trial  the  federal  judge   directed  a  verdict  in
EnergyNorth's  favor on all  issues.  Century  filed an  appeal  with the  First
Circuit  Court of Appeals and oral  argument on Century's  appeal was on January
13,  2006.  A jury trial in the Nashua MGP action  commenced  against the London
Market  Insurers  and Century  Indemnity on November 1, 2005 and on November 14,
2005,  the jury  returned a verdict in favor of KeySpan  finding that London and
Century was obligated to indemnify EnergyNorth of response costs incurred at the
site. We anticipate  that the carriers will appeal this verdict.  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.


                                      148
<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.  During 2005 our gas
distribution  operations employed certain derivative instruments associated with
large-volume  customers  that  were not  subject  to SFAS 71.  Those  derivative
financial instruments settled by year-end.

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, 2005,  Seneca-Upshur has hedge positions in place for approximately
85% of its estimated 2005 through 2008 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  2008.  The  fair  value of these  derivative  instruments  at
December  31, 2005 was a liability of $21.8  million.  The  estimated  amount of
losses  associated with such derivative  instruments  that are reported in other
comprehensive income and that are expected to be reclassified into earnings over
the next twelve months is $9.2 million, or approximately $6.0 million after-tax.
Ineffectiveness   associated  with  these   outstanding   derivative   financial
instruments was immaterial at December 31, 2005.

The Ravenswood Generating Station uses derivative financial instruments to hedge
the cash flow  variability  associated  with the purchase of natural gas or fuel
oil that will be consumed during the generation of  electricity.  The Ravenswood
Generating  Station  also  hedges the cash flow  variability  associated  with a
portion of electric energy sales.

With respect to price exposure associated with fuel purchases for the Ravenswood
Generating  Station,  KeySpan employed the use of  financially-settled  oil swap
contracts  to hedge  the cash  flow  variability  for a  portion  of  forecasted
purchases of fuel oil that was consumed by the Ravenswood Generating Station. We
use 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 fuel oil is through June 2006.  The fair value of these
derivative  instruments at December 31, 2005 was $0.3 million, which is reported
in other  comprehensive  income and is expected to be reclassified into earnings
within the next twelve months. Ineffectiveness associated with these outstanding
derivative financial instruments was immaterial at December 31, 2005.

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  Generating Station.  Our hedging strategy is to hedge
at least 50% of forecasted  on-peak  summer season  electric  energy sales and a


                                      149
<PAGE>


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 August 2006. To accomplish our stated hedging strategy,  KeySpan employs
financially-settled    electric-power    swap    contracts    with    offsetting
financially-settled  oil swap contracts and OTC natural gas swaps. We use market
quoted forward prices to value the electric-power swap contracts. The fair value
of these  derivative  instruments  at December  31, 2005 was $9.5 million all of
which is  expected  to be  reclassified  into  earnings  within the next  twelve
months. We use market quoted forward prices to value the oil swap contracts. The
fair value of these derivative  instruments at December 31, 2005 was a liability
of $6.6 million all of which is expected to be reclassified into earnings within
the next twelve  months.  We use market quoted  forward  prices to value the gas
swap contracts.  The fair value of these derivative  instruments at December 31,
2005 was $0.5 million all of which is expected to be reclassified  into earnings
within  the next  twelve  months.  The  after-tax  benefit  of these  derivative
instruments is anticipated to be $2.2 million.  Ineffectiveness  associated with
these outstanding  derivative  financial  instruments was immaterial at December
31, 2005.

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  for the year ended  December  31, 2005,
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.

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, 2005, these
derivatives  had a fair value of $ 157.6  million and are reflected as a current
asset of $131.6 million and a deferred asset of $26.0 million,  with  offsetting
positions in regulatory  liabilities and deferred  credits of $146.5 million and
$11.1 million, respectively 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.  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


                                      150
<PAGE>


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, 2005,  these  derivatives  had a fair value of $18.4 million and
are  reflected as a deferred  asset of $49.2  million and a regulatory  asset of
$30.9  million with  offsetting  positions in  regulatory  liabilities,  current
liabilities  and  deferred  credits of $28.9  million,  $30.6  million and $20.6
million, respectively on the Consolidated Balance Sheet.

The table below  summarizes the fair value of the above  outstanding  derivative
instruments  at December 31, 2005 and  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.

-----------------------------------------------------------------------------
(In Millions of Dollars)              December 31, 2005    December 31, 2004
-----------------------------------------------------------------------------
Gas Contracts:
  Other current assets                           $ 132.1                 $ -
  Other deferred charges                            75.2                21.7
  Regulatory asset                                  30.9                20.1
  Other current liability                          (39.8)                  -
  Other deferred liabilities                       (44.3)              (43.9)
  Regulatory liability                            (175.4)               (7.4)

Oil Contracts:
  Other current assets                               0.5                 0.3
  Other deferred charges                               -                 7.5
  Other current liability                           (6.8)                  -

Electric Contracts:
  Other current assets                              10.2                 0.3
  Other current liability                           (0.7)
-----------------------------------------------------------------------------
                                                 $ (18.1)             $ (1.4)
-----------------------------------------------------------------------------

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.  During  2004,  we  purchased  a series of call  options on the spread
between  the  price of  heating  oil and the  price of  natural  gas to  further
complement  our  hedging  strategy  regarding  sales  to  certain   large-volume
customers.  As stated,  these positions  settled prior to year end. In addition,
the  Ravenswood  Generating  Station sold a three year option for 30-day peaking
gas service.  The 30-day  peaking gas service is for the following  three winter
seasons: October 2004 - March 2005, October 2005 - March 2006 and October 2006 -
March 2007. For each of these winter seasons,  the  counterparty can call on the
Ravenswood  Generating Station to supply no more than 30,000 Mdth of a gas a day
for no more than 30 days.  We recorded a $0.8  million  gain in other income and
deductions on the Consolidated  Statement of Income to reflect the change in the
market value  associated with this  derivative  instrument for the twelve months
ended December 31, 2005.

Interest Rate Derivative  Instruments:  In January 2005,  KeySpan  redeemed $500
million  of  outstanding  debt - 6.15%  Notes  due  2006,  and  accelerated  the
amortization of approximately $11.2 million of previously  unamortized  benefits
associated  with an  interest  rate  swap on these  notes  that  was  previously
settled.  The accelerated  amortization  was recorded as a reduction to interest
expense.  (See Note 6  "Long-term  Debt and  Commercial  Paper"  for  additional
details regarding the debt  redemption.)  There were no interest rate derivative
instruments outstanding at December 31, 2005.


                                      151
<PAGE>


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.

In 2005, 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  2005/2006  winter  heating  season - November  2005 through March 2006.
These put options will pay KeySpan up to $40,000 per heating degree day when the
actual  temperature  is below 4,169  heating  degree days, or  approximately  5%
warmer than normal, based on the most recent 20-year average for normal weather.
The maximum  amount  KeySpan will receive on these  purchased put options is $16
million.  The net  premium  cost for these  options is $1.2  million and will be
amortized  over the heating  season.  Since  weather was near normal  during the
fourth  quarter of 2005,  there was no  earnings  impact  associated  with these
derivative  instruments  other than the premium cost for purchasing the options.
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.

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  would have paid KeySpan up to $40,000 per heating  degree day
when  the  actual   temperature   was  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  would have received on these
purchased  put options was $16 million.  The net premium cost for these  options
was $1.6 million and was amortized  over the heating  season.  Since weather was
colder  than  normal  during the first  quarter of 2005,  there was no  earnings
impact associated with these derivative  instruments other than the premium cost
for purchasing the options.

Credit  and  Collateral:  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.  In instances where the  counterparties'  credit
quality has declined,  or credit exposure  exceeds certain levels,  we may limit
our  credit  exposure  by  restricting  new  transactions  with  counterparties,
requiring  additional  collateral or credit  support and  negotiating  the early
termination of certain  agreements.  At December 31, 2005,  KeySpan has received
$13.2 million from its counterparties as collateral  associated with outstanding
derivative contracts.  This amount has been recorded as restricted cash, with an
offsetting  position in current  liabilities on the Consolidated  Balance Sheet.
Further,  KeySpan has paid $8.9 million in margin  calls to its  counterparties.
This amount has been recorded as an accounts receivable on the December 31, 2005
Consolidated Balance Sheet.

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.


                                      152
<PAGE>


Long-term Debt: The following  tables depict the fair values and carrying values
of KeySpan's long-term debt at December 31, 2005 and 2004.

Fair Values of Long-Term Debt
------------------------------------------------------------------------------
                                                           December 31,
(In Millions of Dollars)                              2005              2004
------------------------------------------------------------------------------
First Mortgage Bonds                              $   114.1         $   115.8
Notes                                               2,692.1           2,571.8
Gas Facilities Revenue Bonds                          651.3             666.9
Authority Financing Notes                              66.0              66.0
Promissory Notes                                      156.6             159.8
MEDS Equity Units                                         -             480.0
Master Lease                                          430.5             460.9
Tax Exempt Bonds                                      130.8             135.0
------------------------------------------------------------------------------
                                                  $ 4,241.4         $ 4,656.2
------------------------------------------------------------------------------

Carrying Values of Long-Term Debt

------------------------------------------------------------------------------
                                                           December 31,
------------------------------------------------------------------------------
(In Millions of Dollars)                              2005             2004
------------------------------------------------------------------------------
First Mortgage Bonds                              $    95.0         $    95.0
Notes                                               2,437.2           2,485.0
Gas Facilities Revenue Bonds                          640.5             640.5
Authority Financing Notes                              66.0              66.0
Promissory Notes                                      155.4             155.4
MEDS Equity Units                                         -             460.0
Master Lease                                          412.3             412.3
Tax Exempt Bonds                                      128.3             128.3
------------------------------------------------------------------------------
                                                  $ 3,934.7         $ 4,442.5
------------------------------------------------------------------------------

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.  Gas Exploration and Production Property - Depletion

As  described  in Note 2  "Business  Segments,"  during  much of 2004  KeySpan's
investment  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  investment in
these activities also includes its wholly-owned subsidiary Seneca-Upshur.  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  as to the
existence of proved reserves.  Properties are depleted and charged to operations
using the unit of production method.


                                      153
<PAGE>


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.  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 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.

Note 10.    Energy Services - Discontinued Operations

In 2004, the Energy Services segment  experienced  significantly lower operating
profits and cash flows than originally projected.  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,  are 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,  including approximately $5 million 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.
In June  2005,  the  balance  to be paid over the three  year  period  was fully
collected on a present value basis and a significant  portion of the performance
bonds were replaced without any remaining indemnification obligation on the part
of KeySpan.  The current estimated cost to complete  projects  supported by such
indemnity  obligations is approximately $0.2 million.  The buyers have agreed to
complete the projects for which such indemnity  obligations were incurred and to
indemnify  and  hold  KeySpan  harmless  with  respect  to  its  liabilities  in
connection with such bonds.

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


                                      154
<PAGE>


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 December 31,
2005, the total cost to complete such remaining  bonded projects is estimated to
be approximately  $40 million.  The  aforementioned  guarantees are reflected in
Note  7  "Contractual  Obligations,  Financial  Guarantees  and  Contingencies".
KeySpan's  former  subsidiary has also agreed to complete the projects for which
such  indemnity  obligations  were  incurred and to  indemnify  and hold KeySpan
harmless with respect to its liabilities in connection with such bonds.

In  anticipation  of these sales and in connection  with the  preparation of the
third quarter and fourth quarter 2004 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,  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
$0.45 per share) was also  recorded in 2004 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 to
reflect the estimated loss on disposal.

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.

-----------------------------------------------------------------------
                                                           December 31,
(In Millions of Dollars)                                       2004
-----------------------------------------------------------------------

Property                                                      $   8.7
Current assets                                                $  42.9

Current liabilities                                           $  64.2
-----------------------------------------------------------------------


                                      155
<PAGE>

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
                                                             For the Year Ended December 31,
(In Millions of Dollars)                              2005              2004                 2003
----------------------------------------------------------------------------------------------------
<S>                                                   <C>              <C>                  <C>
Revenues                                             $ 33.8           $  338.7              $ 379.6
Less:
    Operating expenses                                 40.2              364.9                385.5
    Goodwill impairment                                   -              108.3                    -
----------------------------------------------------------------------------------------------------
                                                       (6.4)            (134.5)                (5.9)
Income taxes (benefit)                                 (2.3)             (55.5)                (4.0)
----------------------------------------------------------------------------------------------------
Operating income (loss)                                (4.1)             (79.0)                (1.9)
Gain (Loss) on disposal, net of tax                     2.3              (72.0)                   -
----------------------------------------------------------------------------------------------------
Net (Loss)                                           $ (1.8)          $ (151.0)             $  (1.9)
----------------------------------------------------------------------------------------------------
</TABLE>

Note 11.    2006 LIPA Settlement

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,  KeySpan and LIPA entered into three
major  long-term  service  agreements  that (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 "1998 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
"1998 PSA") and other  long-term  agreements  through which we provide LIPA with
approximately  one half 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 "1998 EMA").  We also purchase
energy,  capacity  and  ancillary  services in the open market on LIPA's  behalf
under the 1998 EMA. The 1998 MSA, 1998 PSA and 1998 EMA all became  effective on
May 28, 1998 and are collectively referred to as the 1998 LIPA Agreements.

On February 1, 2006,  KeySpan and LIPA  entered into (i) an amended and restated
Management  Services Agreement (the "2006 MSA"),  pursuant to which KeySpan will
continue to operate and  maintain  the electric T&D System owned by LIPA on Long
Island;  (ii) a new Option and  Purchase  and Sale  Agreement  (the "2006 Option
Agreement"),  to replace the Generation  Purchase Rights  Agreement (as amended,
the "GPRA"),  pursuant to which LIPA had the option,  through December 15, 2005,
to effectively acquire  substantially all of the electric generating  facilities
owned by KeySpan on Long  Island;  and (iii) a Settlement  Agreement  (the "2006
Settlement   Agreement")   resolving  outstanding  issues  between  the  parties
regarding the 1998 LIPA Agreements.  The 2006 MSA, the 2006 Option Agreement and
the 2006 Settlement  Agreement are collectively  referred to herein as the "2006
LIPA  Agreements".  Each of the 2006 LIPA Agreements will become effective as of
January  1, 2006 upon all of the 2006 LIPA  Agreements  receiving  the  required
governmental  approvals;  otherwise none of the 2006 LIPA Agreements will become
effective.

2006 Settlement Agreement

Pursuant to the terms of the 2006 Settlement Agreement,  KeySpan and LIPA agreed
to resolve issues that have existed between the parties  relating to the various
1998 LIPA Agreements. In addition to the resolution of these matters,  KeySpan's
entitlement  to utilize  LILCO's  available tax credits and other tax attributes
will  increase from  approximately  $50 million to  approximately  $200 million.
These  credits  and  attributes  may be used  to  satisfy  KeySpan's  previously


                                      156
<PAGE>


incurred indemnity  obligation to LIPA for any federal income tax liability that
may result from the settlement of a pending  Internal  revenue  Service  ("IRS")
audit for LILCO's tax year ended March 31, 1999. In  recognition of these items,
as  well  as for  the  modification  and  extension  of the  1998  MSA  and  the
elimination of the GPRA, upon effectiveness of the Settlement  Agreement KeySpan
will record a contractual asset in the amount of approximately $160 million,  of
which approximately $110 million will be attributed to the right to utilize such
additional  tax credits and  attributes  and  approximately  $50 million will be
amortized over the eight year term of the 2006 MSA. In order to compensate  LIPA
for the  foregoing,  KeySpan  will pay LIPA $69  million in cash and will settle
certain accounts  receivable in the amount of approximately $90 million due from
LIPA.

Generation Purchase Rights Agreement and 2006 Option Agreement.

Under an amended GPRA,  LIPA had the right to acquire  certain of KeySpan's Long
Island-based  generating assets formerly owned by LILCO, at fair market value at
the time of the exercise of such right.  LIPA was  initially  required to make a
determination  by May 2005,  but  KeySpan  and LIPA agreed to extend the date by
which LIPA was to make this  determination  to December 15, 2005. As part of the
2006  settlement  between  KeySpan and LIPA,  the parties  entered into the 2006
Option  Agreement  whereby LIPA has the option during the period January 1, 2006
to December 31, 2006 to purchase only KeySpan's Far Rockaway and/or E.F. Barrett
Generating  Stations  (and certain  related  assets) at a price equal to the net
book value of each facility.  The 2006 Option  Agreement  replaces the GPRA, the
expiration  of which  has been  stayed  pending  effectiveness  of the 2006 LIPA
Agreements.  In the event such  agreements do not become  effective by reason of
failure  to  secure  the  requisite  governmental  approvals,  the GPRA  will be
reinstated  for a period of 90 days.  If LIPA were to  exercise  the  option and
purchase  one or both of the  generation  facilities  (i) LIPA and KeySpan  will
enter into an operation  and  maintenance  agreement,  pursuant to which KeySpan
will  continue  to operate  these  facilities  for a fixed  management  fee plus
reimbursement  for  certain  costs;  and  (ii) the 1998 PSA and 1998 EMA will be
amended to reflect that the purchased  generating  facilities would no longer be
covered by those  agreements.  It is anticipated that the fees received pursuant
to the  operation  and  maintenance  agreement  will offset the reduction in the
operation and  maintenance  expense  recovery  component of the 1998 PSA and the
reduction in fees under the 1998 EMA.

Management Services Agreements

In place of the previous compensation  structure (whereby KeySpan was reimbursed
for budgeted  costs,  and earned a management  fee and certain  performance  and
cost-based incentives), KeySpan's compensation for managing the T&D System under
the 2006 MSA consists of two  components:  a minimum  compensation  component of
$224 million per year and a variable component based on electric sales. The $224
million  component  will  remain  unchanged  for three  years and then  increase
annually by 1.7%, plus inflation. The variable component, which will comprise no
more than 20% of  KeySpan's  compensation,  is based on  electric  sales on Long
Island  exceeding a base amount of 16,558 gigawatt hours,  increasing by 1.7% in
each year. Above that level,  KeySpan will receive  approximately 1.34 cents per
kilowatt hour for the first contract  year,  1.29 cents per kilowatt hour in the
second  contract  year  (plus an annual  inflation  adjustment),  1.24 cents per
kilowatt hour in the third contract year (plus an annual inflation  adjustment),
with the per  kilowatt  hour rate  thereafter  adjusted  annually by  inflation.
Subject to certain  limitations,  KeySpan will be able to retain all operational
efficiencies realized during the term of the 2006 MSA.


                                      157
<PAGE>


LIPA will  continue to reimburse  KeySpan for certain  expenditures  incurred in
connection  with the  operation  and  maintenance  of the T&D System,  and other
payments made on behalf of LIPA,  including:  real property and other T&D System
taxes, return postage, capital construction expenditures and storm costs.

Note 12.    Subsequent Events

On February 25, 2006,  Keyspan entered into an Agreement and Plan of Merger (the
"Merger   Agreement"),   with  National  Grid  PLC,  a  public  limited  company
incorporated  under the laws of England and Wales  ("Parent")  and National Grid
USA, Inc, a New York  Corporation  ("Merger Sub"),  pursuant to which Merger Sub
will merge with and into KeySpan (the "Merger"),  with KeySpan continuing as the
surviving  Company.  Pursuant to the Merger Agreement,  at the effective time of
the Merger,  each outstanding share of common stock, par value $.01 per share of
KeySpan (the  "Shares"),  other than shares owned by KeySpan,  shall be canceled
and  shall be  converted  into the  right to  receive  $42.00  in cash,  without
interest.

Consummation of the Merger is subject to various closing  conditions,  including
but not  limited  to the  satisfaction  or waiver of  conditions  regarding  the
receipt  of  requisite  regulatory  approvals  and the  adoption  of the  Merger
Agreement by the  stockholders  of KeySpan and the Parent.  Assuming  receipt or
waiver of the  foregoing,  it is currently  anticipated  that the Merger will be
consummated  in early 2007.  However,  no assurance can be given that the Merger
will occur, or, the timing of its completion.

Financial Swap Agreement for In-City Unforced Capacity

Currently, the NYISO's New York City local reliability rules require that 80% of
the  electric  capacity  needs  of  New  York  City  be  provided  by  "in-City"
generators.  On February 6, 2006, the NYISO  Operating  Committee  increased the
"in-City" generator  requirement to 83% beginning in May 2006 through the period
ending on April 2007, based in part on the statewide  reserve margin of 118% set
by the New York State Reliability  Council.  On February 16, 2006, an appeal was
filed with the NYISO  Management  Committee  requesting  that the  February  6th
decision be rejected and that the "in-City" requirement be increased to a larger
percentage  of 83%.  A vote on this  appeal  is  expected  to occur at the NYISO
Management Committee meeting scheduled for February 28, 2006.

Our Ravenswood  Generating  Station is an "in-City"  generator.  As the electric
infrastructure  in New York City and the  surrounding  areas continues to change
and evolve and the demand for electric power increases,  the "in-City" generator
requirement  could be further  modified.  Construction of new  transmission  and
generation  facilities may cause significant  changes to the market for sales of
capacity,  energy and ancillary services from our Ravenswood Generating Station.
Recently  500 MW of capacity  came on line and it is  anticipated  that  another
500MW of new capacity may be available during 2006 as a result of the completion
of an in-City  generation  project  currently  under  construction.  We can not,
however,  be certain as to when the new power plant will be in  operation or the
nature of future New York City  energy,  capacity or ancillary  services  market
requirements or design.

Notwithstanding  the foregoing,  KeySpan continues to believe that New York City
represents a strong capacity market and has entered into an  International  SWAP
Dealers  Association  Master  Agreement for a fixed for float unforced  capacity
financial swap (the "Agreement") with Morgan Stanley Capital Group Inc. ("Morgan
Stanley")  dated as of January 18,  2006.  The  Agreement  has a three year term
beginning May 1, 2006, (assuming a condition to effectiveness has been satisfied
by such date). The notional quantity is 1,800,000kW (the "Notional Quantity") of
In-City Unforced Capacity and the fixed price is $7.57/kW-month ("Fixed Price"),
subject to adjustment  upon the occurrence of certain  events.  Cash  settlement
will occur on a monthly  basis  based on the  In-City  Unforced  Capacity  price
determined  by the relevant New York  Independent  System  Operator  Spot Demand
Curve Auction Market ("Floating Price"). For each monthly settlement period, the
price  difference  will equal the Fixed Price minus the Floating  Price. If such
price  difference is less than zero,  Morgan  Stanley will pay KeySpan an amount
equal to the product of (a) the Notional  Quantity and (b) the absolute value of
such price  difference.  Conversely,  if such price  difference  is greater than
zero,  KeySpan will pay Morgan Stanley an amount equal to the product of (a) the
Notional Quantity and (b) the absolute value of such price  difference.  KeySpan
believes that the average annual monthly capacity market price will settle above
the  Fixed  Price.  This  derivative  instrument  will  not  qualify  for  hedge
accounting  treatment  under  SFAS 133 and  will be  subject  to  mark-to-market
accounting treatment.


                                      158
<PAGE>

Note 13.    KeySpan Gas East Corporation Summary Financial Data

KEDLI is a wholly owned  subsidiary of KeySpan.  KEDLI was formed on May 7, 1998
and on May 28, 1998 acquired  substantially all of the assets related to the gas
distribution  business of LILCO.  KEDLI  provides gas  distribution  services to
customers  in the Long Island  counties  of Nassau and Suffolk and the  Rockaway
peninsula of Queens county.  KEDLI established a program for the issuance,  from
time to time, of up to $600 million  aggregate  principal  amount of Medium-Term

Notes, which will be fully and unconditionally guaranteed by the parent, KeySpan
Corporation.   On  February  1,  2000,  KEDLI  issued  $400  million  of  7.875%
Medium-Term  Notes due 2010.  In January 2001,  KEDLI issued an additional  $125
million of Medium- Term Notes at 6.9% due January 2008. The following  condensed
financial  statements  are required to be disclosed by SEC  regulations  and set
forth those of KEDLI,  KeySpan Corporation as guarantor of the Medium-Term Notes
and our other subsidiaries on a combined basis.
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                               Statement of Income
-----------------------------------------------------------------------------------------------------------------------------------
                                                                          Year Ended December 31, 2005
(In Millions of Dollars)                       Guarantor        KEDLI         Other Subsidiaries     Eliminations      Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                               <C>         <C>                    <C>                  <C>            <C>
Revenues                                        $   0.6       $ 1,432.9              $ 6,229.1          $   (0.6)        $ 7,662.0
                                            ---------------------------------------------------------------------------------------
Operating Expenses
  Purchased gas                                       -           963.0                2,634.3                 -           3,597.3
  Fuel and purchased power                            -               -                  752.1                 -             752.1
  Operations and maintenance                       22.0           133.5                1,462.4                 -           1,617.9
  Intercompany expense                                -             4.8                   (4.2)             (0.6)                -
  Depreciation and amortization                       -            76.9                  319.7                 -             396.6
  Operating taxes                                   0.1            65.9                  341.0                 -             407.0
                                            ---------------------------------------------------------------------------------------
Total Operating Expenses                           22.1         1,244.1                5,505.3              (0.6)          6,770.9
                                            ---------------------------------------------------------------------------------------
Gain on sale of property                              -               -                    1.6                 -               1.6
Income from equity investments                        -               -                   15.1                 -              15.1
                                            ---------------------------------------------------------------------------------------
Operating Income (Loss)                           (21.5)          188.8                  740.5                 -             907.8
                                            ---------------------------------------------------------------------------------------

Interest charges                                 (144.5)          (61.9)                 (83.9)             21.0            (269.3)
Other income and (deductions)                     523.8             2.9                  (81.3)           (446.0)             (0.6)
                                            ---------------------------------------------------------------------------------------
Total Other Income and (Deductions)               379.3           (59.0)                (165.2)           (425.0)           (269.9)
                                            ---------------------------------------------------------------------------------------

Income Taxes (Benefit)                            (32.4)           48.2                  223.5                 -             239.3
                                            ---------------------------------------------------------------------------------------
Earnings from Continuing Operations               390.2            81.6                  351.8            (425.0)            398.6

Discontinued Operations                               -               -                   (1.8)                -              (1.8)
Culmulative Change in Accounting Principal            -            (0.2)                  (6.4)                -              (6.6)
                                            ---------------------------------------------------------------------------------------
Net Income                                      $ 390.2       $    81.4              $   343.6          $ (425.0)        $   390.2
                                            =======================================================================================
</TABLE>
                                      159
<PAGE>
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                               Statement of Income
------------------------------------------------------------------------------------------------------------------------------------
                                                                       Year Ended December 31, 2004
(In Millions of Dollars)                 Guarantor           KEDLI           Other Subsidiaries       Eliminations      Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>           <C>                     <C>                    <C>              <C>
Revenues                                  $   0.6         $ 1,124.4               $ 5,526.1           $   (0.6)           $ 6,650.5
                                      ----------------------------------------------------------------------------------------------
Operating Expenses
  Purchased gas                                 -             664.9                 1,999.6                  -              2,664.5
  Fuel and purchased power                      -                 -                   540.3                  -                540.3
  Operations and maintenance                  5.3             137.8                 1,423.9                  -              1,567.0
  Intercompany expense                          -               5.4                    (5.4)                 -                    -
  Depreciation and amortization                 -              79.9                   471.9                  -                551.8
  Operating taxes                               -              65.7                   338.4                  -                404.1
  Goodwill Impairment                           -                 -                    41.0                  -                 41.0
                                      ----------------------------------------------------------------------------------------------
Total Operating Expenses                      5.3             953.7                 4,809.7                  -              5,768.7
                                      ----------------------------------------------------------------------------------------------

Gain on sale of property                        -                 -                     7.0                  -                  7.0
Income from equity investments                  -                 -                    46.5                  -                 46.5
                                      ----------------------------------------------------------------------------------------------
Operating Income (Loss)                      (4.7)            170.7                   769.9               (0.6)               935.3
                                      ----------------------------------------------------------------------------------------------
Interest charges                           (204.5)            (61.5)                 (267.7)             202.4               (331.3)
Other income and (deductions)               635.4               0.8                   423.9             (723.9)               336.2
                                      ----------------------------------------------------------------------------------------------
Total Other Income and (Deductions)         430.9             (60.7)                  156.2             (521.5)                 4.9
                                      ----------------------------------------------------------------------------------------------

Income Taxes (Benefit)                      (45.5)             35.8                   335.2                  -                325.5
                                      ----------------------------------------------------------------------------------------------
Earnings from Continuing Operations         471.7              74.2                   590.9             (522.1)               614.7

Discontinued Operations                         -                 -                  (151.0)                 -               (151.0)
                                      ----------------------------------------------------------------------------------------------
Net Income                                $ 471.7         $    74.2               $   439.9           $ (522.1)           $   463.7
                                      ==============================================================================================
</TABLE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                               Statement of Income
-----------------------------------------------------------------------------------------------------------------------------------
                                                                        Year Ended December 31, 2003
(In Millions of Dollars)                  Guarantor            KEDLI           Other Subsidiaries      Eliminations    Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                          <C>             <C>                    <C>                    <C>           <C>
Revenues                                    $   0.5          $ 1,046.9              $ 5,488.6            $   (0.5)       $ 6,535.5
                                      ---------------------------------------------------------------------------------------------
Operating Expenses
  Purchased gas                                   -              574.0                1,921.1                   -          2,495.1
  Fuel and purchased power                        -                  -                  414.6                   -            414.6
  Operations and maintenance                   11.3              137.2                1,474.1                   -          1,622.6
  Intercompany expense                          5.3                3.6                   (3.6)               (5.3)               -
  Depreciation and amortization                   -               77.6                  494.1                   -            571.7
  Operating taxes                                 -               77.5                  340.7                   -            418.2
                                      ---------------------------------------------------------------------------------------------
Total Operating Expenses                       16.6              869.9                4,641.0                (5.3)         5,522.2
                                      ---------------------------------------------------------------------------------------------

Gain on sale of property                          -               14.0                    1.1                   -             15.1
Income from equity investments                  0.1                  -                   19.1                   -             19.2
                                      ---------------------------------------------------------------------------------------------
Operating Income (Loss)                       (16.0)             191.0                  867.8                 4.8          1,047.6
                                      ---------------------------------------------------------------------------------------------
Interest charges                             (209.5)             (63.0)                (299.4)              264.2           (307.7)
Other income and (deductions)                 621.1               (8.6)                  54.3              (699.4)           (32.6)
                                      ---------------------------------------------------------------------------------------------
Total Other Income and (Deductions)           411.6              (71.6)                (245.1)             (435.2)          (340.3)
                                      ---------------------------------------------------------------------------------------------

Income Taxes (Benefit)                        (28.7)              40.8                  269.2                   -            281.3
                                      ---------------------------------------------------------------------------------------------
Earnings from Continuing Operations           424.3               78.6                  353.5              (430.4)           426.0

Discontinued Operations                           -                  -                   (1.9)                  -             (1.9)
Cumulative Change in Accounting
Principle                                         -                  -                  (37.4)                  -            (37.4)
                                      ---------------------------------------------------------------------------------------------
Net Income                                  $ 424.3          $    78.6              $   314.2            $ (430.4)       $   386.7
                                      =============================================================================================
</TABLE>
                                      160
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
------------------------------------------------------------------------------------------------------------------------------------
                                                                            December 31, 2005
(In Millions of Dollars)                         Guarantor        KEDLI     Other Subsidiaries       Eliminations      Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                              <C>            <C>              <C>                   <C>              <C>
ASSETS
Current Assets
   Cash and temporary cash investments          $    79.6      $     3.5       $     41.4                              $    124.5
   Accounts receivable, net                           0.6          149.9            822.2                                   972.7
   Other current assets                               4.0          368.9          1,550.0                                 1,922.9
                                             -------------------------------------------------------------------------------------
                                                     84.2          522.3          2,413.6                     -           3,020.1
                                             -------------------------------------------------------------------------------------

Investments and Other                             4,571.0            0.7            128.2              (4,457.5)            242.4
Property                                     -------------------------------------------------------------------------------------
   Gas                                                  -              -          7,275.9                                 7,275.9
   Other                                                -        2,111.3            981.5                                 3,092.8
   Accumulated depreciation and depletion               -         (400.6)        (2,631.2)                               (3,031.8)
   Property of discontinued operations                  -              -                -                                       -
                                             -------------------------------------------------------------------------------------
                                                        -        1,710.7          5,626.2                     -           7,336.9
                                             -------------------------------------------------------------------------------------

Intercompany Accounts Receivable                  2,813.6           44.6             95.6              (2,953.8)                -
Deferred Charges                                    482.5          316.1          2,414.6                                 3,213.2
                                             -------------------------------------------------------------------------------------
Total Assets                                    $ 7,951.3      $ 2,594.4       $ 10,678.2            $ (7,411.3)       $ 13,812.6
                                             =====================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                             $    36.4      $   149.7       $    900.9                              $  1,087.0
  Commercial paper                                  657.6              -                -                                   657.6
  Other current liabilities                         196.2          128.5             85.9                                   410.6
                                             -------------------------------------------------------------------------------------
                                                    890.2          278.2            986.8                     -           2,155.2
                                             -------------------------------------------------------------------------------------
Intercompany Accounts Payable                        51.8          338.3          1,049.8              (1,439.9)                -
                                             -------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                                  27.2          330.6            800.1                                 1,157.9
Other deferred credits and liabilities              634.0          225.3          1,240.0                                 2,099.3
                                             -------------------------------------------------------------------------------------
                                                    661.2          555.9          2,040.1                     -           3,257.2
                                             -------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                       4,485.4          897.0          3,539.3              (4,457.6)          4,464.1
Long-term debt                                    1,862.7          525.0          3,046.9              (1,513.8)          3,920.8
                                             -------------------------------------------------------------------------------------
Total Capitalization                              6,348.1        1,422.0          6,586.2              (5,971.4)          8,384.9
                                             -------------------------------------------------------------------------------------
Minority Interest in Consolidated Companies                                          15.3                                    15.3
                                             -------------------------------------------------------------------------------------
Total Liabilities and Capitalization            $ 7,951.3      $ 2,594.4       $ 10,678.2            $ (7,411.3)       $ 13,812.6
                                             =====================================================================================
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                                      161
<PAGE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                 December 31, 2004
(In Millions of Dollars)                              Guarantor         KEDLI    Other Subsidiaries     Eliminations   Consolidated
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>            <C>              <C>             <C>              <C>
ASSETS
Current Assets
   Cash and temporary cash investments                $   580.7      $    (0.9)       $    342.2       $        -       $    922.0
   Accounts receivable, net                                 0.8          223.6           1,087.6                -          1,312.0
   Other current assets                                     4.5          146.5             650.7                -            801.7
   Assets of discontinued operations                          -              -              42.9                              42.9
                                                 ----------------------------------------------------------------------------------
                                                          586.0          369.2           2,123.4                -          3,078.6
                                                 ----------------------------------------------------------------------------------

Investments and Other                                   4,567.3            2.0             169.1         (4,465.5)           272.9
                                                 ----------------------------------------------------------------------------------
Property
   Gas                                                        -        1,998.5           4,872.7                -          6,871.2
   Other                                                      -              -           2,987.8                -          2,987.8
   Accumulated depreciation and depletion                     -         (334.5)         (2,465.3)               -         (2,799.8)
   Property of discontinued operations                        -              -               8.7                               8.7
                                                 ----------------------------------------------------------------------------------
                                                              -        1,664.0           5,403.9                -          7,067.9
                                                 ----------------------------------------------------------------------------------

Intercompany Accounts Receivable                        2,485.7              -           1,292.2         (3,777.9)               -

Deferred Charges                                          381.3          221.4           2,342.0                -          2,944.7

                                                 ----------------------------------------------------------------------------------
Total Assets                                          $ 8,020.3      $ 2,256.6        $ 11,330.6       $ (8,243.4)      $ 13,364.1
                                                 ==================================================================================

LIABILITIES AND CAPITALIZATION
Current Liabilities
   Accounts payable                                   $    48.4      $   111.5        $    746.7       $        -       $    906.6
  Commercial paper                                        912.2              -                 -                -            912.2
  Other current liabilities                               294.7          167.2             (62.6)               -            399.3
   Liabilities of discontinued operations                     -              -              64.2                              64.2
                                                 ----------------------------------------------------------------------------------
                                                        1,255.3          278.7             748.3                -          2,282.3
                                                 ----------------------------------------------------------------------------------
Intercompany Accounts Payable                                 -          101.3           2,147.8         (2,249.1)               -
                                                 ----------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax                                       (83.2)         298.1             909.2                -          1,124.1
Other deferred credits and liabilities                    534.5          112.0             964.4                -          1,610.9
                                                 ----------------------------------------------------------------------------------
                                                          451.3          410.1           1,873.6                -          2,735.0
                                                 ----------------------------------------------------------------------------------
Capitalization
Common shareholders' equity                             3,940.5          815.6           3,604.2         (4,465.5)         3,894.8
Preferred stock                                            19.7              -                 -                -             19.7
Long-term debt                                          2,353.5          650.9           2,943.1         (1,528.8)         4,418.7
                                                 ----------------------------------------------------------------------------------
Total Capitalization                                    6,313.7        1,466.5           6,547.3         (5,994.3)         8,333.2
                                                 ----------------------------------------------------------------------------------
Minority Interest in Consolidated Companies                   -              -              13.6                -             13.6
                                                 ----------------------------------------------------------------------------------
Total Liabilities and Capitalization                  $ 8,020.3      $ 2,256.6        $ 11,330.6       $ (8,243.4)      $ 13,364.1
                                                 ==================================================================================
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      162
<PAGE>



<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
------------------------------------------------------------------------------------------------------------------------------------
                                                                           Year Ended December 31, 2005
                                                                  ------------------------------------------------------------------
(In Millions of Dollars)                                             Guarantor        KEDLI      Other Subsidiaries     Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
<S>                                                                    <C>           <C>               <C>               <C>
   Net Cash (Used in) Provided by Continuing Operating Activities     $ (327.7)      $ 168.5          $  562.5           $ 403.3
                                                                  ------------------------------------------------------------------
Investing Activities
   Capital expenditures                                                      -        (113.3)           (426.2)           (539.5)
   Cost of removal                                                           -          (2.6)            (25.2)            (27.8)
   Proceeds from sale of property and investments                            -          (2.1)             49.1              47.0
   Derivative margin call                                                    -             -              (8.9)             (8.9)
                                                                  ------------------------------------------------------------------
Net Cash (Used in) Provided by Continuing Investing Activities               -        (118.0)           (411.2)           (529.2)
                                                                  ------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                                  41.2             -                 -              41.2
   Common stock issued associated with MEDS conversion                   460.0             -                 -             460.0
   Issuance (payment) of debt, net                                      (754.6)            -             (15.0)           (769.6)
   Redemption of preferred stock                                         (75.0)            -                 -             (75.0)
   Common and preferred stock dividends paid                            (308.4)            -                 -            (308.4)
   Dividend paid to parent                                               375.0             -            (375.0)                -
   Other                                                                  (1.6)            -              (3.8)             (5.4)
   Net intercompany accounts                                              90.0         (46.1)            (43.9)                -
                                                                  ------------------------------------------------------------------
Net Cash Provided by (Used in) Continuing Financing Activities          (173.4)        (46.1)           (437.7)           (657.2)
                                                                  ------------------------------------------------------------------

Net Increase in Cash and Cash Equivalents                             $ (501.1)      $   4.4          $ (286.4)          $(783.1)
Net Cash Flow from Discontinued Operations                                   -             -             (14.4)            (14.4)
Cash and Cash Equivalents at Beginning of Period                         580.7          (0.9)            342.2             922.0
                                                                  ------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                            $   79.6       $   3.5          $   41.4           $ 124.5
                                                                  ==================================================================
------------------------------------------------------------------------------------------------------------------------------------

</TABLE>


                                      163
<PAGE>
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
------------------------------------------------------------------------------------------------------------------------------------
                                                                                 Year Ended December 31, 2004
                                                         ---------------------------------------------------------------------------
(In Millions of Dollars)                                   Guarantor           KEDLI            Other Subsidiaries      Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>              <C>                     <C>                  <C>
Operating Activities
   Net Cash (Used in) Provided by Operating Activities       $ (88.7)         $ 169.5                $   669.3             $  750.1
                                                         ---------------------------------------------------------------------------
Investing Activities
   Capital expenditures                                            -           (108.7)                  (641.6)              (750.3)
   Cost of removal                                                 -             (7.1)                   (29.2)               (36.3)
   Proceeds from sale of property and investments                  -                -                  1,021.3              1,021.3
                                                         ---------------------------------------------------------------------------
Net Cash (Used in) Provided by Investing Activities                -           (115.8)                   350.5                234.7
                                                         ---------------------------------------------------------------------------
Financing Activities
   Treasury stock issued                                        33.4                -                        -                 33.4
   Issuance (payment) of debt, net                            (269.7)               -                   (170.7)              (440.4)
   Redemption of preferred stock                                (8.5)               -                        -                 (8.5)
   Net proceeds from sale/leaseback transaction                    -                -                    382.0                382.0
   Common and preferred stock dividends paid                  (291.1)               -                        -               (291.1)
   Gain on interest rate swap                                   12.7                -                        -                 12.7
   Dividend paid to parent                                     447.6            (40.0)                  (407.6)                   -
   Other                                                        27.6                -                      8.5                 36.1
   Net intercompany accounts                                   619.8            (16.2)                  (603.6)                   -
                                                         ---------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities            571.8            (56.2)                  (791.4)              (275.8)
                                                         ---------------------------------------------------------------------------

Net Increase in Cash and Cash Equivalents                    $ 483.1          $  (2.5)               $   228.4             $  709.0
Net Cash Flow from Discontinued Operations                         -                -                      9.6                  9.6
Cash and Cash Equivalents at Beginning of Period                97.6              1.6                    104.2                203.4
                                                         ---------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                   $ 580.7          $  (0.9)               $   342.2             $  922.0
                                                         ===========================================================================
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
------------------------------------------------------------------------------------------------------------------------------------
                                                                                   Year Ended December 31, 2003
                                                            ------------------------------------------------------------------------
(In Millions of Dollars)                                      Guarantor        KEDLI           Other Subsidiaries       Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                             <C>           <C>                   <C>                   <C>
Operating Activities
Net Cash (Used in) Provided by Operating Activities            $ (547.5)      $ 164.5               $ 1,606.4             $ 1,223.4
                                                            ------------------------------------------------------------------------
Investing Activities
   Capital expenditures                                               -        (130.3)                 (879.1)             (1,009.4)
   Cost of removal                                                    -          (1.7)                  (29.4)                (31.1)
   Proceeds from the sale of property and subsidiary stock            -          15.1                   294.6                 309.7
   Investments in subsidiaries                                        -             -                  (211.3)               (211.3)
   Issuance of note receiveable                                   (55.0)            -                       -                 (55.0)
                                                            ------------------------------------------------------------------------
Net Cash (Used in) Investing Activities                           (55.0)       (116.9)                 (825.2)               (997.1)
                                                            ------------------------------------------------------------------------
Financing Activities
    Proceeds from equity issuance                                 473.6             -                       -                 473.6
    Treasury stock issued                                          96.7             -                       -                  96.7
    Redemption of LIPA promissory notes                          (447.0)            -                                        (447.0)
    (Payment) issuance of debt, net                              (133.8)            -                   110.2                 (23.6)
    Redemption of preferred stock                                     -             -                   (14.3)                (14.3)
    Common and preferred stock dividends paid                    (280.6)            -                       -                (280.6)
    Other                                                          28.9             -                   (13.9)                 15.0
    Net intercompany accounts                                     874.0         (52.6)                 (821.4)                    -
                                                                                                                                  -
                                                            ------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities               611.8         (52.6)                 (739.4)               (180.2)
                                                            ------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents           $    9.3       $  (5.0)              $    41.8             $    46.1
Net Cash from Discontinued Operations                                 -             -                   (13.3)                (13.3)
Cash and Cash Equivalents at Beginning of Period                   88.3           6.5                    75.8                 170.6
                                                            ------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                     $   97.6       $   1.5               $   104.3             $   203.4
                                                            ========================================================================
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                                      164
<PAGE>


Note 14.    Supplemental Gas and Oil Disclosures (Unaudited)

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. Gas and oil operations,  and reserves,
were located in the United  States in 2003.  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 2005 or 2004.

<TABLE>
<CAPTION>
Capitalized Costs Relating to Gas and Oil Producing Activities
-----------------------------------------------------------------------------------------
                                                                  (In Millions of Dollars)
----------------------------------------------------------------------------------------
At December 31,                                                           2003
----------------------------------------------------------------------------------------
<S>                                                                     <C>
Unproved properties not being amortized                                 $  142.9
Properties being amortized - productive and nonproductive                2,429.9
----------------------------------------------------------------------------------------
Total capitalized costs                                                  2,572.8
Accumulated depletion                                                   (1,159.5)
----------------------------------------------------------------------------------------
Net capitalized costs                                                   $1,413.3
----------------------------------------------------------------------------------------
</TABLE>


Costs Incurred in Property Acquisition, Exploration and Development Activities
-----------------------------------------------------------------------------
                                                     (In Millions of Dollars)
-----------------------------------------------------------------------------
At December 31,                                                  2003
-----------------------------------------------------------------------------
Acquisition of properties -
     Unproved properties                                         $ 61.5
     Proved properties                                            171.3
Exploration                                                        66.3
Development                                                       170.5
Asset retirement obligation                                        31.8
------------------------------------------------------------------------
Total costs incurred                                            $ 501.4
------------------------------------------------------------------------



Costs included in development costs to develop proved  undeveloped  reserves for
the year ended December 31, 2003 were $49.4 million.

Results of Operations from Gas and Oil Producing Activities*
------------------------------------------------------------------------------
                                                      (In Millions of Dollars)
------------------------------------------------------------------------------
At December 31,                                                      2003
------------------------------------------------------------------------------
Revenues                                                         $      497.9
------------------------------------------------------------------------------
Production and lifting costs                                             63.6
Shipping and handling costs                                              10.4
Depletion                                                               205.1
------------------------------------------------------------------------------
Total expenses                                                          279.1
------------------------------------------------------------------------------
Income before taxes                                                     218.8
Income taxes                                                             76.6
------------------------------------------------------------------------------
Results of operations                                            $     142.2
------------------------------------------------------------------------------


*    (Excluding corporate overhead and interest costs)


                                      165
<PAGE>


Summary of Production and Lifting Costs
---------------------------------------------------------------------------
                                                   (In Millions of Dollars)
---------------------------------------------------------------------------
At December 31,                                                     2003
---------------------------------------------------------------------------
Pumping, gauging and other labor                                    $ 11.0
Compressors and other rental equipment                                 5.1
Property taxes and insurance                                           7.2
Transportation                                                         2.3
Processing fees                                                        2.4
Workover and well stimulation                                          5.2
Repairs, maintenance and supplies                                      3.7
Fuel and chemicals                                                     3.1
Environmental, regulatory and other                                    7.6
Severance taxes                                                       16.0
---------------------------------------------------------------------------
Total production and lifting costs                                  $ 63.6
---------------------------------------------------------------------------


For  December  31, 2003 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
----------------------------------------------------------------
Proved Reserves
   Beginning of year                                    614,734
   Revisions of previous estimates                      (32,433)
   Extensions and discoveries                           140,632
   Production                                          (100,130)
   Purchases of reserves in place                        89,380
----------------------------------------------------------------
Proved reserves - End of year (1)                       712,183
Proved developed reserves
   Beginning of year                                    435,629
   End of Year (2)                                      488,012
----------------------------------------------------------------
(1)  Includes minority interest of 318,417.
(2)  Includes minority interest of 218,190.


                                      166
<PAGE>


Crude Oil, Condensate and Natural Gas Liquids (MBbls)
------------------------------------------------------------------
At December 31,                                            2003
------------------------------------------------------------------
Proved reserves
Beginning of Year                                           9,548
Revisions of previous estimates                            (3,542)
Extension and discoveries                                     117
Production                                                 (1,514)
Purchases of reserves in place                              3,753
------------------------------------------------------------------
Proved reserves - End of year (1)                           8,362
Proved developed reserves
Beginning of year                                           2,413
End of year (2)                                             4,273
------------------------------------------------------------------
(1)  Includes minority interest of 3,739.
(2)  Includes minority interest of 1,910.

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.  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.

Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Gas and Oil Reserves

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------
                                                               (In Millions of Dollars)
---------------------------------------------------------------------------------------
At December 31,                                                                 2003
---------------------------------------------------------------------------------------
<S>                                                                           <C>
Future cash flows                                                            $ 4,375.8
Future costs-
Production                                                                      (769.9)
Development                                                                     (378.6)
---------------------------------------------------------------------------------------
Future net inflows before income tax                                           3,227.3
Future income taxes                                                             (853.4)
---------------------------------------------------------------------------------------
Future net cash flows                                                          2,373.9
10% discount factor                                                             (853.4)
---------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows (1)                 $ 1,520.5
---------------------------------------------------------------------------------------
</TABLE>
(1)  Includes minority interest of $672,620.


                                      167
<PAGE>


 Changes in Standardized Measure of Discounted Future Net
 Cash Flows from Proved Reserve Quantities
-------------------------------------------------------------------------------
                                                       (In Millions of Dollars)
-------------------------------------------------------------------------------
 At December 31,                                                     2003
-------------------------------------------------------------------------------
 Standardized measure - beginning of year                            $ 1,103.9
 Sales and transfers, net of production costs                           (492.3)
 Net change in sales and transfer prices, net
      of production costs                                                384.3
 Extensions and discoveries and improved
      recovery, net of related costs                                     434.3
 Changes in estimated future development costs                            (9.4)
 Development costs incurred during the period
      that reduced future development costs                               81.0
 Revisions of quantity estimates                                        (123.9)
 Accretion of discount                                                   142.3
 Net change in income taxes                                             (236.5)
 Net purchases of reserves in place                                      254.0
 Sales of reserves in place                                                  -
 Changes in production rates (timing) and other                          (17.2)
-------------------------------------------------------------------------------
 Standardized measure - end of year                                  $ 1,520.5
-------------------------------------------------------------------------------


Average Sales Prices and Production Costs Per Unit
-------------------------------------------------------------------------
Year Ended December 31,                                            2003
-------------------------------------------------------------------------
Average Sales Price*
     Natural gas ($/Mcf)                                            5.23
     Oil, condensate and natural gas liquid ($/Bbl)                28.26
Production cost per equivalent Mcf ($)                              0.58
-------------------------------------------------------------------------
*Represents the cash price  received  which  excludes  the effect of any hedging
 transactions.

Note 15.    Summary of Quarterly Information (Unaudited)

The  following is a table of financial  data for each quarter of KeySpan's  year
ended December 31, 2005.
<TABLE>
<CAPTION>
                                                                                                Quarter Ended
--------------------------------------------------------------------------------------------------------------------------------
          (In Millions of Dollars, Except Per Share Amounts)            3/31/2005        6/30/2005       9/30/2005     12/31/2005
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                       <C>           <C>            <C>
Operating Revenue                                                         2,480.5          1,342.5       1,303.1        2,535.9
Operating Income                                                            438.7            103.2         102.8          263.1
Earnings (loss) from continuing operations,
     less preferred stock dividends                                         234.4             18.0          22.6          121.4
Cumulative change in accounting principles, net of tax                          -                -             -           (6.6) (a)
Earnings (loss) from discontinued operations                                    -             (1.8)            -              -
Earnings (loss) for common stock                                            234.4             16.2          22.6          114.8
Basic earnings per common share from continuing operations
     less preferred stock dividends                                          1.45             0.11          0.13           0.70
Basic earnings per common share from discontinued operations                    -            (0.01)            -              -
Basic earnings per common share from cumulative change in accounting
 principles                                                                     -                -             -          (0.04) (a)
Basic earnings per common share                                              1.45             0.10          0.13           0.66
Diluted earnings per common share                                            1.44             0.09          0.13           0.65
Dividends declared                                                          0.455            0.455         0.455          0.455
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(a)  Cumulative  change in  accounting  principles  for  implementation  of FASB
     Interpretation   No.  47  ("FIN  47")  "Accounting  for  Conditional  Asset
     Retirement Obligations."


                                      168
<PAGE>


The  following is a table of financial  data for each quarter of KeySpan's  year
ended December 31, 2004.
<TABLE>
<CAPTION>
                                                                                         Quarter Ended
---------------------------------------------------------------------------------------------------------------------------------
         (In Millions 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                                               2,510.6       1,277.8             975.6             1,886.5
Operating Income                                                  487.6         122.2  (a)         87.6  (c)          237.9  (e)
Earnings (loss) from continuing operations,
     less preferred stock dividends                               246.6         128.5  (a)(b)     (30.1) (c)(d)       264.1  (e)(f)
Earnings (loss) from discontinued operations (g)                   (0.4)          0.8             (87.0)              (64.4)
Earnings (loss) for common stock                                  246.2         129.3            (117.1)              199.7
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          -             -             (0.54)              (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 in Houston Exploration and 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 and 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 $151.0  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 $11.1 million.


                                      169

<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, 2005 and 2004, 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, 2005.  Our audits also
included the financial statement schedules listed in the Index at Item 15. These
financial statements and financial statement schedules are the responsibility of
the Company's  management.  Our  responsibility  is to express an opinion on the
financial statements and financial statement schedules 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,  2005  and  2004,  and the  results  of their
operations  and their cash flows for each of the three years in the period ended
December 31, 2005, in conformity with accounting  principles  generally accepted
in the United States of America.  Also, in our opinion, such financial statement
schedules,  when  considered  in  relation to the basic  consolidated  financial
statements  taken as a whole,  present  fairly,  in all material  respects,  the
information set forth therein.

As discussed in Note 1(P) to the consolidated financial statements,  on December
31,  2003,   the  Company   adopted   Financial   Accounting   Standards   Board
Interpretation No. ("FIN") 46 "Consolidation of Variable Interest  Entities,  an
Interpretation  of ARB No.  51".  As  discussed  in Notes  1(O),  1(P) and 7, on
December 31, 2005, the Company adopted FIN 47, "Accounting for Conditional Asset
Retirement Obligations, an interpretation of FASB Statement No. 143."

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, 2005, 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,  2006  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
------------------------
New York, New York
February 28, 2006








                                      170
<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,  2005.  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.




                                      171
<PAGE>



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, 2005.  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,  2005,  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, 2005, which is included herein.






                                      172
<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, 2005,  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.


                                      173

<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, 2005,  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, 2005, 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  schedules  as of and for the  year  ended
December  31,  2005 of the  Company  and our  report  dated  February  28,  2006
expressed an  unqualified  opinion on those  financial  statements and financial
statement schedules and included an explanatory paragraph regarding the adoption
of Financial  Accounting  Standards Board Interpretation No. 47, "Accounting for
Conditional  Asset Retirement  Obligations,  an interpretation of FASB Statement
No. 143",  referred to in Notes 1(O), 1 (P) and 7.

/s/Deloitte & Touche LLP
------------------------
New York,  New York
February 28, 2006


                                      174




<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 23, 2006,  following  the  recommendation  of the  Compensation  and
Management Development Committee (the "Compensation Committee"), KeySpan's Board
of Directors set the 2006 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 2006  base  salaries  are as
follows:  Mr. Catell - $1,140,000,  Mr. Fani - $782,000,  Mr. Parker - $625,000,
Mr.  Zelkowitz -  $625,000,  and Mr.  Luterman - $488,000.  All 2006 base salary
increases are effective January 1, 2006, with the exception of Mr. Luterman. Mr.
Luterman's base salary increase is effective February 1, 2006.

Also on February 23, 2006,  following  the  recommendation  of the  Compensation
Committee, the Board approved the performance-based  incentive awards to be paid
to our  executive  officers  for the year ending  December  31, 2005 ("FY 2005")
under the KeySpan  Corporate Annual Incentive  Compensation Plan (the "Corporate
Plan"). The Corporate Plans provides for performance-based incentive awards as a
percentage  of  cumulative  base  salary  paid  during the  calendar  year.  The
Compensation   Committee  had  approved  the  target  performance  award  levels
applicable to the Corporate  Plan for FY 2005 in December 2004. In January 2005,
the  Compensation  Committee  approved the performance  goals relating to the FY
2005  Corporate  Plan for the named  executive  officers  based on financial and
performance measures, including goals relating to earnings per share, cash flow,
business unit operating income,  diversity  initiatives,  customer satisfaction,
work place safety and other individual  strategic goals and  initiatives.  Based
upon actual FY 2005 performance, an award payout for each of the named executive
officers was approved as follows: Mr. Catell - $1,400,000,  Mr. Fani - $741,175,
Mr. Parker - $550,090, Mr. Zelkowitz - $513,129, and Mr. Luterman - $388,282.

In December  2005, the Board  approved the  compensation  formulas for incentive
awards that may be paid to our executive  officers for the year ending  December
31,  2006  ("FY   2006")   under  the   Corporate   Plan.   For  FY  2006,   the
performance-based  target award levels for each of the named executive  officers
will remain the same as last year.  The target  performance  award levels are as
follows:  Mr. Catell - 100%,  Mr. Fani - 75%, Mr. Parker - 70%, Mr.  Zelkowitz -
70% and Mr. Luterman - 65%.

Also in December  2005,  the  Compensation  Committee  approved the target award
levels for performance-based  equity awards that may be granted to our executive
officers  for  FY  2006  under  the  KeySpan  Long-Term   Performance  Incentive
Compensation Plan (the "Long-Term Incentive Plan"). The target award levels have
been modified from last year. The target award levels are designed to align with
industry  benchmarks at 50th percentile  levels.  The FY 2006 target performance
award levels for the named executive officers are as follows: Mr. Catell - 240%,
Mr. Fani - 160%,  Mr.  Parker - 125%,  Mr.  Zelkowitz - 125% and Mr.  Luterman -
110%.

                                      175

<PAGE>


On February 23,  2006,  the  Compensation  Committee  also  approved the FY 2006
grants  pursuant to the Long Term  Incentive  Plan. The  Compensation  Committee
awarded the following  grants to the named  executive  officers  based on actual
2005 performance as follows: Mr. Catell - 85,520 shares of restricted stock; Mr.
Fani - 38,930 performance  shares;  Mr. Parker - 24,320 performance  shares; Mr.
Zelkowitz - 27,490  performance  shares;  and Mr. Luterman - 18,360  performance
shares.

Mr.  Catell's  restricted  stock has a two year  restriction  period which shall
lapse on February  23,  2008 or the  Compensation  Committee  has the ability to
accelerate  vesting  after one year based on certain goals being  achieved.  The
performance shares for the remaining four named executives will be measured over
the three year period  beginning on January 1, 2006  through  December 31, 2008,
with  performance  results  linked to the percentage of improvement in Return on
Invested  Capital  ("ROIC") and Total  Shareholder  Return  ("TSR").  The actual
number of shares to be  awarded  at the end of the  performance  period  will be
determined  using a  sliding  scale  which  encompasses  both  the  ROIC and TSR
measures.  The ROIC goal will act as the  primary  trigger.  If the ROIC goal is
below threshold,  all shares will be forfeited without payment regardless of the
performance of TSR.

For  further  information  on  executive  compensation  see "Item 11.  Executive
Compensation" herein.


                                      176


<PAGE>



                                    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 XXX,
2006 (the "Proxy Statement"). The information required by this item is set forth
under the caption "Executive Officers of KeySpan" 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) Beneficial Ownership Reporting  Compliance" contained in the Proxy
Statement, which information is incorporated herein by reference thereto.

ITEM 11.    EXECUTIVE COMPENSATION

The information  required by this item 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 AND
            RELATED STOCKHOLDER MATTERS

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 2006 Audit Firm Fee Summary" and "Report of the
Audit  Committee" in the Proxy  Statement,  which  information  is  incorporated
herein by reference thereto.

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:


                                      177
<PAGE>


o    Consolidated  Statement of Income for the year ended December 31, 2005, the
     year ended December 31, 2004, and the year ended December 31, 2003

o    Consolidated Statement of Retained Earnings for the year ended December 31,
     2005,  the year ended  December 31, 2004,  and the year ended  December 31,
     2003

o    Consolidated Balance Sheet at December 31, 2005 and December 31, 2004

o    Consolidated  Statement of Capitalization at December 31, 2005 and December
     31, 2004

o    Consolidated  Statement of Cash Flows for the year ended December 31, 2005,
     the year ended December 31, 2004, and the year ended December 31, 2003

o    Consolidated  Statement of Comprehensive Income for the Year ended December
     31, 2005,  the year ended December 31, 2004 and the year ended December 31,
     2003

o    Notes to Consolidated Financial Statements

o    Report of the Independent Registered Public Accounting Firm






                                      178
<PAGE>


2.   Financial Statement Schedules

Consolidated  Schedule of Valuation and  Qualifying  Accounts for the year ended
December 31, 2005, the year ended December 31, 2004, and the year ended December
31, 2003.


<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------
                                                                   Balance at      Charged to                      Balance at
                                                                  Beginning of     costs and        Net              End of
                             Descriptions                             Period        expenses     Deductions          Period
-----------------------------------------------------------------------------------------------------------------------------
(In Millions of Dollars)
<S>                                                                   <C>           <C>            <C>              <C>
Twelve Months Ended December 31, 2005
-------------------------------------
     Deducted from asset accounts:
          Allowance for doubtful accounts                        $      67.8     $     96.8    $    101.8        $     62.8

     Additions to liability accounts:
          Reserve for injury and damages                         $       9.4     $      0.5    $      0.6        $      9.3
          Reserve for environmental expenditures                 $     256.8     $    210.6    $     43.7        $    423.7

Twelve Months Ended December 31, 2004
-------------------------------------
     Deducted from asset accounts:
          Allowance for doubtful accounts                        $      75.7     $     74.1    $     82.0        $     67.8

     Additions to liability accounts:
          Reserve for injury and damages                         $       9.4     $        -    $        -        $      9.4
          Reserve for environmental expenditures                 $     294.7     $        -    $     37.9        $    256.8

Twelve Months Ended December 31, 2003
-------------------------------------
     Deducted from asset accounts:
          Allowance for doubtful accounts                        $      60.1     $     82.1    $     66.5        $     75.7

     Additions to liability accounts:
          Reserve for injury and damages                         $      25.8     $      3.9    $     20.3        $      9.4
          Reserve for environmental expenditures                 $     232.1     $    106.3    $     43.7        $    294.7
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>

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


                                      179

<PAGE>


(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 KeySpan  effective  April 16, 1998,
          Amendment to Certificate of Incorporation of KeySpan effective May 26,
          1998,  Amendment to Certificate of Incorporation of KeySpan  effective
          June 1, 1998, Amendment to the Certificate of Incorporation of KeySpan
          effective   April  7,  1999  and  Amendment  to  the   Certificate  of
          Incorporation of KeySpan  effective May 20, 1999 (filed as Exhibit 3.1
          to KeySpan's Form 10-Q for the quarterly period ended June 30, 1999)

3.2       By-Laws of KeySpan in effect as of June 25, 2003, as amended (filed as
          Exhibit 3.1 to KeySpan's Form 10-Q for the quarterly period ended June
          30, 2003)

4.1       Credit Agreement dated as of June 24, 2005 among KeySpan  Corporation,
          the  several  lenders,  The Royal Bank of Scotland  PLC and  Citibank,
          N.A., as Co-Syndication  Agents,  The Bank of New York and The Bank of
          Nova Scotia,  as  Co-Documentation  Agents,  and JPMorgan  Chase Bank,
          N.A., as Administrative  Agent (filed as Exhibit 4.1 to KeySpan's Form
          8-K dated as of June 29, 2005)

4.2       Amended and Restated Credit  Agreement dated as of June 24, 2005 among
          KeySpan  Corporation,  the several lenders, The Royal Bank of Scotland
          PLC and Citibank, N.A., as Co-Syndication Agents, The Bank of New York
          and The Bank of Nova Scotia, as Co-Documentation  Agents, and JPMorgan
          Chase Bank,  N.A.,  as  Administrative  Agent (filed as Exhibit 4.2 to
          KeySpan's Form 8-K dated as of June 29, 2005)

4.3       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
          KeySpan's Form 8-K on November 20, 2000)

4.4       Form of Note  issued in  connection  with the  issuance of the KeySpan
          Corporation  $700  million of 7.625% Notes due 2010 issued on November
          20, 2000 (filed as Exhibit 4-c to  KeySpan's  Form 8-K on November 20,
          2000)

4.5       Form of Note  issued in  connection  with the  issuance of the KeySpan
          Corporation $250 million of 8.0% Notes due 2030 issued on November 20,
          2000 (filed as Exhibit 4-d to KeySpan's Form 8-K on November 20, 2000)


                                      180
<PAGE>


4.6       Form of Note  issued in  connection  with the  issuance of the KeySpan
          Corporation $150 million of 4.65% Notes issued on April 1, 2003 (filed
          as Exhibit 4.1 to KeySpan's Form 8-K dated as of April 8, 2003)

4.7       Form of Note  issued in  connection  with the  issuance of the KeySpan
          Corporation  $150  million  of  5.875%  Notes  issued on April 1, 2003
          (filed as Exhibit 4.2 to KeySpan's Form 8-K dated as of April 8, 2003)

4.8       Form of Note  issued in  connection  with the  issuance of the KeySpan
          Corporation  $307.2  million of 5.803%  Notes issued on March 29, 2005
          (filed  as  Exhibit  4.1 to  KeySpan's  Form 8-K dated as of March 31,
          2005)

4.9       Supplemental  Remarketing  Agreement  dated as of March 21, 2005 among
          KeySpan  Corporation,  J.P. Morgan  Securities Inc. and JPMorgan Chase
          Bank,  N.A. in connection  with the  remarketing of the 4.9% Notes due
          2008 (filed as Exhibit  99.1 to  KeySpan's  Form 8-K dated as of March
          24, 2005)

4.10      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 KeySpan's and KeySpan Gas
          East Corporation's Form S-3 Registration Statement No. 333-92003)

4.11      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 KeySpan's Form 8-K on February 1, 2000)

4.12      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  KeySpan's  Form  10-K for the year  ended
          December 31, 2000)

4.13      Participation  Agreement,  dated as of July 1, 1991,  between New York
          State Energy  Research and Development  Authority  ("NYSERDA") and The
          Brooklyn  Union Gas  Company  relating to the Gas  Facilities  Revenue
          Bonds ("GFRBs") Series 1991A and 1991B (The Brooklyn Union Gas Company
          Project)  (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form
          10-K for the year ended September 30, 1991)

4.14      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 (The Brooklyn Union Gas Company Project) (filed
          as Exhibit 4 to The  Brooklyn  Union Gas  Company's  Form 10-K for the
          year ended September 30, 1991)


                                      181
<PAGE>


4.15      Participation Agreement, dated as of July 1, 1992, between NYSERDA and
          The Brooklyn Union Gas Company  relating to the GFRBs Series 1993A and
          1993B (The Brooklyn Union Gas Company  Project) (filed as Exhibit 4 to
          The  Brooklyn  Union  Gas  Company's  Form  10-K  for the  year  ended
          September 30, 1992)

4.16      Indenture  of Trust,  dated as of July 1, 1992,  between  NYSERDA  and
          Chemical  Bank,  as Trustee,  relating to the GFRBs  Series  1993A and
          1993B (The Brooklyn Union Gas Company  Project) (filed as Exhibit 4 to
          The Brooklyn Union Gas Company Form 10-K for the year ended  September
          30, 1992)

4.17      Participation  Agreement  dated as of July 1, 1991 between NYSERDA and
          The  Brooklyn  Union Gas Company  relating to the GFRBs  Series D (The
          Brooklyn  Union  Gas  Company  Project)  (filed  as  Exhibit  4 to The
          Brooklyn  Union Gas Company's  Form 10-K for the year ended  September
          30, 1991)

4.18      First  Supplemental  Participation  Agreement dated as of June 1, 1993
          between  NYSERDA and The Brooklyn Union Gas Company  relating to GFRBs
          Series D (The Brooklyn Union Gas Company  Project) (filed as Exhibit 4
          to The  Brooklyn  Union Gas  Company's  Form  10-K for the year  ended
          September 30, 1993)

4.19      Trust  Indenture,  dated  as of  July  1,  1991  between  NYSERDA  and
          Manufacturers  Hanover  Trust  Company  relating to the GFRBs Series D
          (filed as Exhibit 4 to The Brooklyn  Union Gas Company's Form 10-K for
          the year ended September 30, 1991)

4.20      First Supplemental  Trust Indenture,  dated as of June 1, 1993 between
          NYSERDA and Chemical Bank (as successor to Manufacturers Hanover Trust
          Company)  relating  to the GFRBs  Series D (filed as  Exhibit 4 to The
          Brooklyn  Union Gas Company's  Form 10-K for the year ended  September
          30, 1993)

4.21      Participation  Agreement,  dated January 1, 1996,  between NYSERDA and
          The  Brooklyn  Union Gas Company  relating  to GFRBs  Series 1996 (The
          Brooklyn  Union  Gas  Company  Project)  (filed  as  Exhibit  4 to The
          Brooklyn  Union Gas Company's  Form 10-K for the year ended  September
          30, 1996)

4.22      Indenture  of Trust,  dated  January  1,  1996,  between  NYSERDA  and
          Chemical Bank, as Trustee, relating to GFRBs Series 1996 (The Brooklyn
          Union Gas Company  Project)  (filed as Exhibit 4 to The Brooklyn Union
          Gas Company's Form 10-K for the year ended September 30, 1996)


                                      182
<PAGE>


4.23      Participation Agreement,  dated as of January 1, 1997, between NYSERDA
          and The  Brooklyn  Union Gas  Company  relating to GFRBs 1997 Series A
          (The Brooklyn  Union Gas Company  Project)  (filed as Exhibit 4 to The
          Brooklyn  Union Gas Company's  Form 10-K for the year ended  September
          30, 1997)

4.24      Indenture of Trust,  dated January 1, 1997,  between NYSERDA and Chase
          Manhattan  Bank,  as  Trustee,  relating  to GFRBs 1997  Series A (The
          Brooklyn  Union  Gas  Company  Project)  (filed  as  Exhibit  4 to The
          Brooklyn  Union Gas Company's  Form 10-K for the year ended  September
          30, 1997)

4.25      Supplemental  Trust  Indenture,  dated as of January  1, 2000,  by and
          between NYSERDA and The Chase Manhattan Bank, as Trustee,  relating to
          the GFRBs  1997  Series A (The  Brooklyn  Union Gas  Company  Project)
          (filed as  Exhibit  4.11 to  KeySpan's  Form  10-K for the year  ended
          December 31, 1999)

4.26      Bond  Purchase  Agreement,  dated as of October  26,  2005,  among The
          Brooklyn  Union Gas  Company  and  NYSERDA  and  Morgan  Stanley & Co.
          Incorporated,   BNY  Capital  Markets,   Inc.,   Sovereign  Securities
          Corporation,  LLC and The Williams  Capital  Group,  L.P., as Series A
          Underwriters,  for the  issuance  of $82 million  aggregate  principal
          amount of 4.7% GFRBs,  2005, Series A. (The Brooklyn Union Gas Company
          Project)  (filed as Exhibit 10.1 to KeySpan's  Form 8-K dated November
          1, 2005)

4.27      Indenture of Trust,  dated as of November 1, 2005, between NYSERDA and
          Citibank,  N.A.,  as Trustee,  relating to the issuance of $82 million
          GFRBs,  2005 Series A, 4.7% due February 2024 (The Brooklyn  Union Gas
          Company Project) (filed as Exhibit 10.1 to KeySpan's Form 10-Q for the
          quarterly period ended September 30, 2005)

4.28      Participation Agreement, dated as of November 1, 2005, between NYSERDA
          and The  Brooklyn  Union Gas Company  relating to the  issuance of $82
          million GFRBs, 2005 Series A, 4.7% due February 2024 (filed as Exhibit
          10.2 to KeySpan's Form 10-Q for the quarterly  period ended  September
          30, 2005)

4.29      Promissory  Note,  dated  as of  November  1,  2005,  executed  by the
          Brooklyn  Union Gas Company for  issuance of $82 million  GFRBs,  2005
          Series A, 4.7% due  February  2024 (filed as Exhibit 10.3 to KeySpan's
          Form 10-Q for the quarterly period ended September 30, 2005)


                                      183
<PAGE>


4.30      Bond  Purchase  Agreement,  dated as of October  26,  2005,  among The
          Brooklyn  Union Gas Company and NYSERDA and Goldman  Sachs & Co.,  BNY
          Capital Markets, Inc., Sovereign Securities  Corporation,  LLC and The
          Williams  Capital  Group,  L.P.,  as  Series A  Underwriters,  for the
          issuance of $55 million  aggregate  principal  amount of GFRBs,  2005,
          Series B (filed as Exhibit 10.2 to KeySpan's  Form 8-K dated  November
          1, 2005)

4.31      Indenture of Trust,  dated as of November 1, 2005, between NYSERDA and
          Citibank,  N.A.,  as Trustee,  relating to the issuance of $55 million
          GFRBs, 2005 Series B due June 2025 (filed as Exhibit 10.4 to KeySpan's
          Form 10-Q for the quarterly period ended September 30, 2005)

4.32      Participation Agreement, dated as of November 1, 2005, between NYSERDA
          and The  Brooklyn  Union Gas Company  relating to the  issuance of $55
          million GFRBs, 2005 Series B, due February 2025 (filed as Exhibit 10.5
          to KeySpan's  Form 10-Q for the quarterly  period ended  September 30,
          2005)

4.33      Promissory  Note,  dated  as of  November  1,  2005,  executed  by the
          Brooklyn Union Gas Company for the issuance of $55 million GFRBs, 2005
          Series B, due June 2025 (filed as Exhibit 10.6 to KeySpan's  Form 10-Q
          for the quarterly period ended September 30, 2005)

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

4.35      Participation  Agreement  dated as of  December 1, 1997 by and between
          NYSERDA and Long Island Lighting Company relating to the 1997 Electric
          Facilities  Revenue Bonds (EFRBs),  Series A (KeySpan  Generation LLC)
          (filed as  Exhibit  10(a) to  KeySpan's  Form  10-Q for the  quarterly
          period ended September 30, 1998)

4.36      Indenture  of Trust,  dated as of  December  1, 1997,  by and  between
          NYSERDA and The Chase Manhattan Bank, as Trustee, relating to the 1997
          EFRBs,  Series A (KeySpan  Generation  LLC) (filed as Exhibit 10(a) to
          KeySpan's Form 10-Q for the quarterly period ended September 30, 1998)

4.37      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 (PCRB's),  Series A (filed as Exhibit
          4.10 to KeySpan's Form 10-K for the year ended December 31, 1999)


                                      184
<PAGE>


4.38      Trust  Indenture,  dated as of October 1, 1999, by and between NYSERDA
          and The Chase Manhattan Bank, as Trustee,  relating to the 1999 PCRBs,
          Series A (filed as Exhibit  4.10 to  KeySpan's  Form 10-K for the year
          ended December 31, 1999)

4.39      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))

4.40      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)

4.41      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)

4.42      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)

4.43      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)

4.44      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)

4.45      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)

4.46      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)

4.47      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 KeySpan's
          Form 10-K for the year ended December 31, 2003)

4.48      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 KeySpan's
          Form 10-K for the year ended December 31, 2003)


                                      185
<PAGE>


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

4.50      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 KeySpan's Form 10-K for
          the year ended December 31, 2003)

4.51      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 KeySpan's Form 10-K for
          the year ended December 31, 2003)

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

4.53      Lease Agreement, dated June 9, 1999, between  KeySpan-Ravenswood,  LLC
          and  LIC  Funding,  Limited  Partnership  (filed  as  Exhibit  10.2 to
          KeySpan's Form 10-Q for the quarterly period ended June 30, 1999)

4.54      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 KeySpan's  Form 10-K for the year ended  December
          31, 2002)

4.55      KeySpan Corporation Guaranty dated June 9, 1999, from KeySpan in favor
          of  LIC  Funding,  Limited  Partnership  (filed  as  Exhibit  10.1  to
          KeySpan's Form 10-Q for the quarterly period ended June 30, 1999)

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

4.57      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(filed as Exhibit 10.2
          to KeySpan's Form 10-Q for the quarterly period ended June 30, 2004)

4.58      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 (filed as Exhibit 10.3 to KeySpan's Form 10-Q for
          the quarterly period ended June 30, 2004)


                                      186
<PAGE>


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

4.60      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)

10.1      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 the Joint
          Registration  Statement on Form S-4 of The Brooklyn  Union Gas Company
          and Long Island Lighting  Company,  Registration No. 333-30353 on June
          30, 1997)

10.2      Management  Services Agreement between Long Island Power Authority and
          Long Island Lighting Company dated as of June 26, 1997 (filed as Annex
          D to the  Joint  Registration  Statement  on Form S-4 of The  Brooklyn
          Union Gas Company and Long Island Lighting  Company,  Registration No.
          333-30353 on June 30, 1997)

10.3      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 KeySpan's Form 10-K for the year ended December 31, 2002)

10.4      Management  Services Agreement dated as of January 1, 2006 between the
          Long Island Lighting Company ("LILCO") d/b/a LIPA and KeySpan Electric
          Services  LLC (filed as Exhibit  10.1 to  KeySpan's  Form 8-K filed on
          February 6, 2005)

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
          the Joint Registration Statement on Form S-4 of The Brooklyn Union Gas
          Company and Long Island Lighting  Company,  Registration No. 333-30353
          on June 30, 1997)

10.6      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)


                                      187
<PAGE>

10.7      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 KeySpan's Form 10-K for the year ended December 31, 2002)


10.8      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  KeySpan's  Form 10-K for the year  ended
          December 31, 2001)

10.9      Amendment,  dated as of March 29, 2002, to Generation  Purchase Rights
          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 KeySpan's  Form 10-Q for the  quarterly
          period ended March 31, 2002)

10.10     Generation  Purchase Right Extension Agreement between KeySpan and the
          Long  Island  Power  Authority  dated as of March 28,  2005  (filed as
          Exhibit 10.1 to  KeySpan's  Form 10-Q for the  quarterly  period ended
          March 31, 2005)

10.11     Option  Agreement dated as of January 1, 2006 between LILCO d/b/a LIPA
          and KeySpan Electric  Services LLC (filed as Exhibit 10.2 to KeySpan's
          Form 8-K filed on February 6, 2005)

10.12     Settlement  Agreement  dated as of  January  1,  2006  among  KeySpan,
          KeySpan  Generation LLC, KeySpan Electric Services LLC, KeySpan Energy
          Trading Services LLC and LIPA (filed as Exhibit 10.3 to KeySpan's Form
          8-K filed on February 6, 2005)

10.13     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)

10.14     Second  Amendment,  dated as of March 24, 2005, to the Lease Agreement
          dated as of September 15, 1998 between The Brooklyn  Union Gas Company
          and Forest City Jay Street  Associates,  L.P.  (filed as Exhibit 10 to
          KeySpan's Form 8-K dated as of March 30, 2005)


                                      188
<PAGE>


10.15     ISDA Master Agreement,  dated as of January 18, 2006,  between KeySpan
          Corporation  and Morgan Stanley  Capital Group Inc.  (filed as Exhibit
          10.1 to KeySpan's Form 8-K dated January 24, 2006)

10.16     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 Form 10-Q
          for the quarter ended September 30, 2000, File No. 001-11899)

10.17     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)

10.18     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)

10.19     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)

10.20     Share Sale and  Purchase  Agreement  dated  February  25, 2005 with BG
          Energy  Holdings  Limited and Premier  Transmission  Financing  Public
          Limited Company (filed as Exhibit 10.37 to KeySpan's Form 10-K for the
          year ended December 31, 2004)

10.21     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 (filed as Exhibit 10.35 to KeySpan's
          Form 10-K for the year ended December 31, 2004)

10.22     Purchase Agreement,  dated February 11, 2005, among WDF Holding Corp.,
          WDF, Inc. and KeySpan Business Solutions,  LLC (filed as Exhibit 10.36
          to KeySpan's Form 10-K for the year ended December 31, 2004)

                             Compensation Agreements
                             -----------------------

10.23*    Cash Compensation for Non-Management Directors of KeySpan

10.24*    Base Salaries of Named  Executive  Officers of KeySpan in effect as of
          February 23, 2006


                                      189
<PAGE>


10.25     Employment  Agreement,  dated February 24, 2005,  between  KeySpan and
          Robert B. Catell  (filed as Exhibit  10.10 to KeySpan's  Form 10-K for
          the year ended December 31, 2004)

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

10.27     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)

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

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

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

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

10.32     Directors'  Deferred  Compensation Plan effective April 2003 (filed as
          Exhibit  10.16 to  KeySpan's  Annual  Report on Form 10-K for the year
          ended December 31, 2003)

10.33     Officers'  Deferred Stock Unit Plan of KeySpan  Corporation  (filed as
          Exhibit  10.17 to  KeySpan's  Annual  Report on Form 10-K for the year
          ended December 31, 2002)

10.34     Officers' Deferred Stock Unit Plan of KeySpan Services, Inc. (filed as
          Exhibit  10.18 to  KeySpan's  Annual  Report on Form 10-K for the year
          ended December 31, 2002)

10.35     Corporate Annual Incentive Compensation and Gainsharing Plan (filed as
          Exhibit 10.20 to KeySpan's  Form 10-K for the year ended  December 31,
          2000)

10.36*    Corporate Annual Incentive  Compensation Plan Target Performance Award
          Level for Fiscal Year 2006

10.37     Senior  Executive  Change of Control  Severance  Plan  effective as of
          October 29, 2003 (filed as Exhibit  10.20 to  KeySpan's  Form 10-K for
          the year ended December 31, 2003)


                                      190
<PAGE>


10.38     KeySpan's Amended Long-Term  Performance  Incentive  Compensation Plan
          (filed as Exhibit A to KeySpan's 2001 Proxy  Statement  filed on March
          23, 2001)

10.39*    KeySpan's   Long-Term   Performance   Incentive    Compensation   Plan
          Performance Target Award Level for Fiscal 2006

14        Code of Ethics (filed as Exhibit 14 to KeySpan's Annual Report on 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

24.1*     Power of Attorney  executed by Andrea S.  Christensen  on February 22,
          2006

24.2*     Power of Attorney executed by Robert J. Fani on February 22, 2006

24.3*     Power of Attorney executed by Alan H. Fishman on February 22, 2006

24.4*     Power of Attorney executed by James R. Jones on February 22, 2006

24.5*     Power of Attorney executed by James L. Larocca on February 22, 2006

24.6*     Power of Attorney executed by Gloria C. Larson on February 22, 2006

24.7*     Power of Attorney executed by Stephen W. McKessy on February 22, 2006

24.8*     Power of Attorney executed by Edward D. Miller on February 22, 2006

24.9*     Power of Attorney executed by Vikki L. Pryor on February 22, 2006

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


                                      191
<PAGE>


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




                                      192
<PAGE>


                                   SIGNATURES

     Pursuant  to the  requirements  of  Section  13 or 15(d) of the  Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

KEYSPAN CORPORATION
(Registrant)


Signature:                                                    Date:

By: /s/Gerald Luterman                                        February 28, 2006
    ------------------
Gerald Luterman
Executive Vice President
and Chief Financial Officer



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

Signatures:                                                   Date:


By: /s/Robert B. Catell                                       February 28, 2006
    ---------------------------
Robert B. Catell
Chairman of the Board of Directors
and Chief Executive Officer


By: /s/Gerald Luterman                                        February 28, 2006
    ------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer


By: /s/Theresa A. Balog                                       February 28, 2006
    -------------------
Theresa A. Balog
Vice President and
Chief Accounting Officer



                                      193
<PAGE>


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


*
---------------------
Robert J. Fani
President, Chief Operating Officer and Director


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



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


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


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


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


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


*
--------------
Vikki L. Pryor
Director

*    Such signature has been affixed pursuant to a Power of Attorney filed as an
     exhibit hereto and incorporated herein by reference thereto



                                      194