SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

          [X ]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
                  EXCHANGE ACT OF 1934
                                       OR
          [    ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                  SECURITIES EXCHANGE ACT OF 1934
            For the period from January 1, 2000 to December 31, 2000

                         Commission File Number 1-14161

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


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



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

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

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

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

           SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
                                      None
                                (Title of class)
           Indicate  by check mark  whether  the  registrant:  (1) has filed all
reports  required to be filed by Section 13 or 15(d) of the Securities  Exchange
Act of 1934 during the preceding 12 months (or for such shorter  period that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days. Yes. X No.
           Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained  herein,  and will not be contained,
to the best of  registrant's  knowledge,  in  definitive  proxy  or  information
statements  incorporated  by  reference  in Part  III of this  Form  10-K or any
amendment to this Form 10-K. X
           As of March 1, 2001,  the aggregate  market value of the common stock
held by non-affiliates (133,745,586 shares) of the registrant was $5,165,254,531
based on the closing price, on such date, of $38.62 per share).
           As of March 1, 2001, there were  137,014,409  shares of common stock,
$.01 par value, outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE

                       Proxy  Statement  dated March 23, 2001 is incorporated by
reference into Part III hereof.



<PAGE>



                               KEYSPAN CORPORATION
                               INDEX TO FORM 10-K


<TABLE>
<CAPTION>

                                                                Part I                                                      Page
<S>            <C>                                                                                                            <C>
Item 1.        Business.........................................................................................................2
Item 2.        Properties......................................................................................................33
Item 3.        Legal Proceedings...............................................................................................33
Item 4.        Submission of Matters to a Vote of Security Holders.............................................................33

                                                                Part II

Item 5.        Market for Registrant's Common Equity and Related Stockholder Matters...........................................34
Item 6.        Selected Financial Data.........................................................................................35
Item 7.        Management's Discussion and Analysis of Financial Condition and Results
                     of Operations.............................................................................................36
Item 7A.       Quantitative and Qualitative Disclosures About Market Risk .....................................................36
Item 8.        Financial Statements and Supplementary Data ....................................................................36
Item 9.        Changes in and Disagreements with Accountants on Accounting and
                     Financial Disclosure......................................................................................36

                                                               Part III

Item 10.       Directors and Executive Officers of the Registrant..............................................................36
Item 11.       Executive Compensation..........................................................................................36
Item 12.       Security Ownership of Certain Beneficial Owners and Management..................................................36
Item 13.       Certain Relationships and Related Transactions..................................................................36
Item 14.       Exhibits, Financial Statement Schedules and Reports on Form 8-K.................................................37

</TABLE>



                                       -1-

<PAGE>



                                     PART I

Item 1.  Business

                                    Overview

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

Our core  business  is gas  distribution,  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 2.4 million customers. In New York, The Brooklyn Union Gas Company
d/b/a  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  d/b/a 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 Company distributes natural gas in eastern
and central Massachusetts;  Colonial Gas Company distributes natural gas in Cape
Cod and eastern Massachusetts;  and Essex Gas Company distributes natural gas in
eastern  Massachusetts.   In  New  Hampshire,   EnergyNorth  Natural  Gas,  Inc.
distributes gas to customers  principally located in central New Hampshire.  Our
newly  acquired  New England  gas  companies  are all doing  business as KeySpan
Energy Delivery New England ("KEDNE").

KEDNY  was  formed  in  1895  through  the  consolidation  of  several  existing
companies,  the oldest of which  commenced  operations  in 1849,  providing  gas
distribution services throughout the New York City Boroughs of Brooklyn,  Staten
Island and most of Queens,  New York.  LILCO,  the original owner of KEDLI's gas
assets,  was organized in 1910 to provide  electric and gas services in the Long
Island Counties of Nassau and Suffolk and the Rockaway  peninsula in the Borough
of  Queens,  all in New York.  KEDLI,  was  formed on May 7, 1998 and on May 28,
1998,  acquired  substantially  all of the LILCO gas  assets  and  provides  gas
distribution  services in Nassau,  Suffolk and the Rockaway peninsula in Queens.
Boston Gas Company has been  wholly-owned  by Eastern since 1929 and has been in
business  for 177 years,  making it the second  oldest gas company in the United
States. Essex Gas Company has been in business for 146 years and was acquired by
Eastern in  September  1998.  Colonial  Gas Company has been in business for 150
years and was acquired by Eastern in August 1999.



                                       -2-

<PAGE>



We are also a major, and growing,  generator of electricity.  We own and operate
five large  generating  plants and 42 smaller  facilities  in Nassau and Suffolk
Counties on Long Island and the Rockaway  peninsula and Queens. In addition,  we
own, lease and operate a major generating  facility in Queens County in New York
City. Under contractual  arrangements,  we provide power,  electric transmission
and distribution services, billing and other customer services for approximately
one million electric customers of the Long Island Power Authority ("LIPA").

Our other  subsidiaries  are involved in gas and oil exploration and production;
gas storage; wholesale and retail gas and electric marketing; appliance service;
heating,  ventilation and air conditioning  ("HVAC")  installation and services;
large  energy-system   ownership,   installation  and  management;   engineering
services; fiber optic services;  energy-related internet activities; fuel cells;
and marine transportation,  including the barge hauling of fuel and other cargo.
We also invest in, and participate in the  development  of,  pipelines and other
energy-related projects, domestically and internationally.


As a result of the  acquisition  of  Eastern  and ENI,  we  became a  registered
holding company under PUHCA.  Therefore,  our corporate and financial activities
and those of our  subsidiaries,  including their ability to pay dividends to us,
are subject to regulation by the  Securities  and Exchange  Commission  ("SEC").
Under our holding company structure, we have no independent operations or source
of income of our own and conduct substantially all of our operations through our
subsidiaries  and, as a result,  we depend on the earnings and cash flow of, and
dividends or distributions from, our subsidiaries to provide the funds necessary
to meet our debt and contractual obligations. Furthermore, a substantial portion
of our  consolidated  assets,  earnings  and  cash  flow  is  derived  from  the
operations of our regulated utility  subsidiaries,  whose legal authority to pay
dividends or make other  distributions  to us is subject to  regulation by state
regulatory authorities.

For additional  information concerning regulation by the SEC under PUHCA see the
discussion  under the heading  "Securities and Exchange  Commission  Regulation"
contained in Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations" contained herein.

KeySpan  reports its  operations  in six business  segments:  Gas  Distribution,
Electric  Services,  Energy  Services,  Gas Exploration  and Production,  Energy
Investments and Other.

The Gas Distribution  segment consists of our six gas distribution  subsidiaries
described  earlier,  which operate in New York,  Massachusetts and New Hampshire
and serve approximately 2.4 million customers.

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



                                       -3-

<PAGE>



The Gas  Exploration  and  Production  segment is engaged in natural gas and oil
exploration and production,  and the development and the acquisition of domestic
natural  gas and oil  properties  primarily  in the Gulf of Mexico and  Southern
Texas.  This  segment  consists of our  approximate  70% equity  interest in The
Houston Exploration Company ("Houston  Exploration") and KeySpan Exploration and
Production, LLC ("KeySpan Exploration"),  our wholly owned subsidiary engaged in
a joint venture with Houston Exploration.

The Energy  Services  segment  primarily  provides  energy-related  services  to
customers  located  within  the New York City  metropolitan  area,  New  Jersey,
Connecticut, Massachusetts, New Hampshire, Rhode Island and Pennsylvania through
various  subsidiaries which operate under the following  principal four lines of
business:  (i) home  energy  services,  which  provides  residential  and  small
commercial  customers  with  service  and  maintenance  of  energy  systems  and
appliances,  as  well  as the  competitive  retail  supply  of  natural  gas and
electricity  to  residential  and  small  commercial  customers;  (ii)  business
solutions,  which provides  engineering,  consulting and construction  services,
services  related  to  the  design,   construction,   installation,   operation,
maintenance and management of heating,  cooling and power  production  equipment
and systems, including ventilating, air conditioning,  electrical power, motors,
pumps, lighting, water, wastewater,  plumbing, piping, fire suppression systems,
for commercial  and  industrial  customers,  as well as the  competitive  retail
supply of natural gas and  electricity to large  commercial,  institutional  and
industrial  customers . Certain  subsidiaries  within this line of business also
engage or may engage in the financing and ownership of cogeneration, small power
production,  thermal energy, chilled water and related equipment and facilities;
(iii) commodity procurement,  which provides management and procurement services
for fuel  supply and  management  of energy  sales,  primarily  for and from the
Ravenswood  facility,  as well as provides wholesale gas and electric purchasing
and management services for the home energy services and business solutions; and
(iv) fiber optic  services,  which  provides  fiber optic related  construction,
leasing and exchange services.

Subsidiaries in the Energy Investments segment hold a 20% equity interest in the
Iroquois Gas Transmission  System,  LP ("Iroquois"),  a pipeline that transports
Canadian gas supply to markets in the Northeastern United States; a 50% interest
in the Premier  Transco  Pipeline  and a 24.5%  interest in Phoenix  Natural Gas
Limited,  both in Northern Ireland;  investments of natural gas processing plans
and related  facilities in Western Canada,  principally  through KeySpan Canada,
formerly Gulf  Midstream  Services and hold minor  investments  in certain other
domestic pipeline projects.

The Other segment represents  primarily  unallocated  administrative and general
expenses,  interest income earned on temporary cash  investments,  and preferred
stock  dividends.  Further,  this  segment  includes  our marine  transportation
subsidiary,  Midland  Enterprises,  that  was  acquired  as part of the  Eastern
acquisition.  We are required by the SEC to sell this  subsidiary by November 8,
2003 as its operations  were  determined not to be  functionally  related to our
core utility operations as required by PUHCA. These operations do not contribute
significantly to our consolidated results of operations or cash flows.

In 1998,  KeySpan  changed its fiscal year end from March 31 to December 31. For
financial reporting purposes,  financial statements included, or incorporated by
reference,  herein  for the period  ending  December  31,  1998 are for the nine
months then ended and have been prepared on the basis


                                       -4-

<PAGE>



that LILCO was deemed the  acquiring  company in the 1998  KeySpan  transaction.
Additional  information about KeySpan's industry segments is contained in Note 2
to the Consolidated  Financial  Statements,  "Business Segments" included herein
and incorporated by reference thereto.

Certain  statements  contained  in this  Annual  Report on Form 10-K  concerning
expectations,  beliefs, plans, objectives,  goals, strategies,  future events or
performance and underlying  assumptions and other statements that are other than
statements of historical  facts,  are  "forward-looking  statements"  within the
meaning of Section  21E of the  Securities  Exchange  Act of 1934,  as  amended.
Without  limiting the  foregoing,  all  statements  under the captions  "Item 7.
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations" and "Item 7A. Quantitative and Qualitative  Disclosures About Market
Risk" relating to our future outlook,  anticipated capital expenditures,  future
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding,  are forward-looking  statements.  Such  forward-looking
statements  reflect  numerous  assumptions  and  involve  a number  of risks and
uncertainties  and actual results may differ  materially from those discussed in
such  statements.  Among the factors that could cause  actual  results to differ
materially are: general economic conditions,  especially in the Northeast United
States;  available  sources  and  cost of fuel;  federal  and  state  regulatory
initiatives that increase  competition,  threaten cost and investment  recovery,
and impact rate  structures;  the ability of KeySpan to successfully  reduce its
cost structure; the successful integration of KeySpan's subsidiaries,  including
Eastern,  ENI and  their  subsidiaries;  the  degree to which  KeySpan  develops
unregulated business ventures,  as well as federal and state regulatory policies
affecting  KeySpan's ability to retain and operate such business  ventures;  the
ability of KeySpan to identify and make complementary  acquisitions,  as well as
the  successful  integration  of  such  acquisitions;  inflationary  trends  and
interest rates;  and other risks detailed from time to time in other reports and
other  documents  filed by KeySpan  with the SEC.  For any of these  statements,
KeySpan claims the protection of the safe harbor for forward-looking information
contained in the Private  Securities  Litigation Reform Act of 1995, as amended.
For additional  discussion on these risks,  uncertainties  and assumptions,  see
"Item 1. Business," "Item 7.  Management's  Discussion and Analysis of Financial
Condition and Results of Operations" and "Item 7A.  Quantitative and Qualitative
Disclosures About Market Risk" contained herein.

KeySpan's  principal  executive  offices  are located at One  MetroTech  Center,
Brooklyn,  New York 11201 and 175 East Old Country  Road,  Hicksville,  New York
11801 and its telephone numbers are (718) 403-1000 (Brooklyn) and (516) 755-6650
(Hicksville).  Financial and other  information  is also  available  through the
World Wide Web at http://www.keyspanenergy.com.


                                Business Strategy

KeySpan's vision is to be the premier energy company in the Northeastern  United
States. To help us achieve that goal, we have acquired the operations of Eastern
and ENI,  establishing  KeySpan as the largest gas  distribution  company in the
Northeast and the fifth  largest in the United  States.  The increased  size and
scope  of the  company  should  enable  us to  provide  enhanced  cost-effective
customer  service;  offer our existing  customers an array of other services and
products by implementing  innovative  marketing techniques and building upon our
existing relationships with


                                       -5-

<PAGE>



them; and capitalize on the above-average  growth  opportunities for natural gas
expansion in the Northeast by expanding our infrastructure on Long Island and in
New England.

A key element of KeySpan's  business  strategy is the continued focus and growth
of our  core  businesses  of gas  distribution,  electric  services  and  energy
services.  In order provide the greatest  shareholder value, we may consider the
sale  of  some  or all of our  non-core  assets  which  include  the  businesses
conducted in our Gas  Exploration  and  Production,  Energy  Investments and our
Other business segments.  Any proceeds from such sales would, in all likelihood,
be used to retire a portion of our outstanding indebtedness.

Gas Distribution Services.  KeySpan has achieved a high degree of penetration in
KEDNY's  service  territory,  with  approximately  79% of all one and two family
homes currently using natural gas for space heating. In contrast,  less than 40%
of one and two family homes in KEDLI's  service  territory  and less than 50% of
one and two family homes in KEDNE's  service  territories  currently use natural
gas for space  heating.  During 2000,  we continued  the  implementation  of our
innovative  marketing techniques focused on oil to gas space heating conversions
and the  conversion  of our existing  non- heating  natural gas customers to gas
heating.   In  our  New  York  markets,   this   approach   resulted  in  24,000
installations, concentrated primarily in our Long Island service territory.

We also  implemented  the same  marketing  programs  in our newly  acquired  New
England service territories, resulting in 19,000 new installations. Our strategy
is to  continue  these  marketing  efforts  primarily  on Long Island and in New
England.  We believe  that more than half of our gas sales growth will come from
our KEDNE  service  territories  where  there are more  than  650,000  potential
customers,  mostly  homeowners who heat their homes with oil. Of these potential
customers,  more than 100,000  already use gas for cooking or water  heating and
another 160,000 are in close proximity to a gas main. Converting these customers
to gas heat will require minimal capital investment.

Additionally, we are also committed to expanding our gas distribution systems on
Long Island and in New England.  During 2000, we installed  more than  1,000,000
feet of new gas main in our  KEDLI  service  territory,  twice as much as in any
previous  year.  Expanding  our gas  distribution  systems  allows us to add new
customers,  providing  a  broader  customer  base  to  expand  our  markets  for
additional products and services.

Electric Services.  Our electric services segment  contributed  significantly to
earnings  in  2000,  largely  attributable  to sales of  capacity,  energy,  and
ancillary  services from our Ravenswood  facility.  We are planning on expanding
the Ravenswood facility by adding a 250-megawatt,  gas-fired co- generation unit
that is  expected  to come on line in 2003.  We are also  considering  expanding
capacity on Long Island by building a combined-cycle generating unit.

Over the  last  year,  we also  focused  our  efforts  on  improving  our  plant
efficiencies to increase generating capacity.  Through innovative  technological
approaches,  such as adding water spray to smaller units, we increased installed
capacity on Long Island and New York City by 37  megawatts,  and we instituted a
program  to reduce  nitrogen  oxides  for  improved  environmental  performance.
Reliability  improvements at our Ravenswood  facility  reduced our forced outage
rate from 35% two years ago to just 5% in 2000.  Decreasing  the  amount of time
our generating units are offline for


                                       -6-

<PAGE>



repairs allows us to increase sales and thus increase  earnings.  Our goal is to
continue improving our plants through new technologies that improve efficiencies
and reliability.

Energy  Services.  With our strong market presence in the Northeast  centered on
our gas  distribution  services and by taking  advantage of the increasing trend
towards deregulation and competition,  KeySpan believes it is well positioned to
provide our  customers  with an expanded  array of energy  products and services
through our unregulated energy services companies.  Our goal is to become one of
the top regional service providers in the Northeast.

During  2000,  KeySpan  expanded  its energy  services  operations  through  the
acquisition  of  four  additional   companies  located  in  the  New  York  City
metropolitan    area.    The   newly    acquired    companies    specialize   in
engineering-consulting,   plumbing   and   mechanical   contracting   and   HVAC
contracting. Additionally, Eastern and ENI each have unregulated energy services
operations in  Massachusetts  and New  Hampshire,  thereby  expanding our energy
services operations further into the Northeast.  The Energy Services segment now
has more than 3,000  employees  and  100,000  contracts  for the sale of gas and
electricity at retail on an unregulated basis.

Additionally,  our fiber optic services  continue to enhance our Energy Services
segment.  Our 450 miles,  or 57,000 fiber miles, of fiber optics located on Long
Island are  strategically  situated in one of the most attractive  communication
markets in the United States.  We construct  fiber optic systems and facilities,
and own and lease fiber optic cable to local, long distance  trans-Atlantic  and
internet service  providers.  Our goal is to continue to expand this business by
broadening  our  customer  base and  creating  strategic  alliances  with  other
telecommunication companies. To this end, we entered into an agreement with FLAG
Atlantic 1, a British  telecommunications  joint  venture,  to  establish a high
speed telecommunications link between London, Paris and New York.

Gas Exploration & Production. The shortages in energy supply and high gas prices
created the opportunity  for  significant net income and shareholder  value from
this segment.  Further, in March 2000, we converted approximately $80 million in
debt owed by Houston Exploration to us into additional common equity, increasing
our ownership from approximately 64% to 70%.

Energy  Investments.  Consistent with KeySpan's  strategy to make investments in
certain select energy related businesses, focused primarily in the Northeast and
Canada,  we purchased  the  remaining  50% interest in KeySpan  Canada from Gulf
Canada Resources Limited. KeySpan also entered into a joint venture to construct
the Islander East Pipeline, which will bring 250 MDTH of gas capacity daily from
Nova Scotia, Canada to Long Island, New York and will also provide an additional
connection  to gas supply for our New England  marketplace.  The  Islander  East
Pipeline is scheduled to become operational in 2003.

Other. As we previously discussed, we are required by the SEC to sell our marine
transportation subsidiary, Midland Enterprises, that was acquired as part of the
Eastern  acquisition since its operations were determined not to be functionally
related to our core utility operations.

New Lines of  Business.  During  2000,  we launched  the  myHomeKey.com  portal.
MyHomeKey  provides  customers with the ability to electrically  manage numerous
household tasks by linking them


                                       -7-

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with  service  providers,  allowing  on-line  scheduling  of  home  repairs  and
maintenance,  convenient  shopping for home  appliances,  one-stop  shopping for
utility services and access to energy saving  equipment and systems,  as well as
individualized community information.

In addition to using  internet  applications  to enhance  customer  contact with
KeySpan, we are also using e-business  solutions to operate more efficiently and
reduce our costs.  In 2000,  KeySpan  entered into a supply chain venture called
Enporion. Enporion is an open, global supply chain e- marketplace for the energy
industry,  linking suppliers and buyers through the internet.  Through Enporion,
we have been able to simplify  business  purchasing  processes,  make operations
more  effective and  efficient,  and reduce the purchase  costs of materials and
supplies.

KeySpan  is  also  engaged  in  alternative  generation   technologies  such  as
microturbines,  reciprocating engines, fuel cells, photovoltaic, and wind power.
We believe that  distributed  generation  methods such as these will be a growth
area in the next few  years.  In  2000,  we  successfully  installed  the  first
microturbine  unit on Long Island at the  Atlantis  Marine World  Aquarium.  The
unit, which runs on natural gas,  produces up to 28 kilowatts of electricity for
the aquarium  and uses its exhaust  heat to provide hot water to the  facility's
shark tank.

The Company

                                Gas Distribution

Overview

KeySpan sells, distributes and transports natural gas in six service territories
located in three states, New York,  Massachusetts and New Hampshire.  We are the
fifth largest gas  distribution  company in the United States and the largest in
the  Northeast.  In New York  there are two  separate,  but  contiguous  service
territories  served by KEDNY and KEDLI,  comprising  approximately  1,417 square
miles, and 1.6 million customers. In Massachusetts, Boston Gas Company, Colonial
Gas  Company  and Essex Gas  Company,  each doing  business as KEDNE serve three
contiguous   service   territories   consisting   of  1,934   square  miles  and
approximately 758,000 customers. In New Hampshire, EnergyNorth Natural Gas, Inc.
d/b/a KEDNE has a service territory that is contiguous to Colonial Gas Company's
and is within 30 to 85 miles of the greater Boston area. EnergyNorth Natural Gas
services approximately 74,000 customers over a service area of approximately 922
square  miles.  Collectively,   KeySpan  owns  and  operates  gas  distribution,
transmission and storage systems that consist of  approximately  21,000 miles of
gas mains and distribution pipelines and 576 miles of transmission pipelines, as
well as two major gas storage  facilities.  Our service areas cover 4,273 square
miles, and we serve approximately 2.4 million customers in the aggregate.

Gas is offered  for sale to  residential  and small  commercial  customers  on a
"firm" basis, and to most large commercial and industrial  customers on a "firm"
or "interruptible" basis. "Firm" service is offered to customers under schedules
or contracts which anticipate no interruptions,  whereas "interruptible" service
is offered to customers under schedules or contracts which anticipate and permit
interruption on short notice,  generally in peak-load seasons.  Gas is available
at any time of the year on an  interruptible  basis, if the supply is sufficient
and the supply system is adequate.


                                       -8-

<PAGE>



KeySpan also participates in interstate  markets by releasing  pipeline capacity
or bundling pipeline  capacity with gas for "off-system"  sales. An "off-system"
customer  consumes  gas at  facilities  located  outside  of  KeySpan's  service
territories by connecting to our facilities or another transporter's  facilities
at a point of  delivery  agreed  to by us and the  customer.  KeySpan  purchases
natural  gas  for  sale  to  customers  under  long-term  supply  contracts  and
short-term  spot  contracts.  Such  gas  is  transported  under  both  firm  and
interruptible transportation contracts. In addition, KeySpan has commitments for
the provision of gas storage capability and peaking supplies.

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

Our gas operations can be significantly affected by seasonal weather conditions.
Traditionally,  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 operate under a utility tariff that contains
a weather normalization  adjustment that provides for recovery from or refund to
firm customers of material shortfalls or excesses of firm net revenues (revenues
less applicable gas costs) during a heating season due to variations from normal
weather.  However,  the  utility  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.  For
additional  discussion,  see Item 7,  Management's  Discussion  and  Analysis of
Financial Condition and Results of Operations, "Regulation and Rate Matters".



                                       -9-

<PAGE>



Gas sales and revenues for 2000 by class of customer are set forth below:

<TABLE>
<CAPTION>

                                                                       Sales                    Revenues                  Revenues
Customer                                                               (MDTH)               (thousands of $)            (% of Total)
-----------------------------------------------------------       ----------------       ----------------------       --------------
<S>                                                                  <C>                        <C>                          <C>
Firm
Residential Heating........................................            127,467                    1,352,215                   52.91
Residential Non-Heating....................................             11,214                      226,592                    8.87
Temperature-Controlled heating.............................             33,490                      224,792                    8.80
Commercial/Industrial......................................             43,829                      389,620                   15.24
                                                                  ------------       ----------------------       -----------------
Total Firm.................................................            216,000                    2,193,219                   85.82
                                                                  ------------       ----------------------       -----------------
Firm Transportation........................................             40,655                       34,709                    1.36
Transportation - Electric Generation.......................             49,854                       10,253                     .40
                                                                  ------------       ----------------------       -----------------
Total Firm Transportation..................................             90,509                       44,962                    1.76
                                                                  ------------       ----------------------       -----------------
  Total Firm Gas Sales and Transportation..................            306,509                    2,238,181                   87.58
Interruptible..............................................              8,016                       46,849                    1.83
Off-System Sales...........................................             32,640                      122,967                    4.81
Transportation.............................................             50,750                      121,996                    4.77
                                                                  ------------       ----------------------       -----------------
  Total Gas Sales and Transportation.......................            397,915                    2,529,993                   98.99
Other Retail Services......................................                  -                       25,792                    1.01
                                                                  ------------       ----------------------       -----------------
  Total Sales and Revenues.................................            397,915                    2,555,785                  100.00
                                                                  ============       ======================       =================
</TABLE>
Further  information and statistics  regarding our Gas  Distribution  segment is
contained in Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations, "Gas Distribution."

Supply and Storage

KeySpan has  contracts  for the purchase of firm  long-term  transportation  and
storage services.  Our gas supplies are purchased under long-term  contracts and
on the spot market and are transported by interstate pipelines from domestic and
Canadian  sources.  Storage and peaking  supplies  are  available to meet system
requirements during winter periods.

Regulatory  actions,  economic  factors  and  changes  in  customers  and  their
preferences  continue  to  reshape  our gas  operations  markets.  A  number  of
multi-family,  commercial  and  industrial  customers  and a  growing  number of
residential  customers  currently  purchase  their gas supplies from natural gas
marketers  and then  contract  with us for local  transportation,  balancing and
other unbundled  services.  This trend is likely to continue as state regulators
in all  of  our  service  territories  have  implemented  policies  designed  to
encourage  customers  to  purchase  their  gas  from  suppliers  other  than the
traditional gas utilities, such as marketers.

New York Gas Distribution Systems

Peak-Day  Capability.  The design  criteria for  KeySpan's  New York gas systems
assumes  an  average  temperature  of 0(0)F  for  peak-day  demand.  Under  such
criteria, KEDNY and KEDLI estimated that


                                      -10-

<PAGE>



their  requirements  to supply firm gas customers would be  approximately  1,940
MDTH of gas for a  peak-day  during  the  2000/2001  winter  season and that gas
available to KEDNY and KEDLI on such a peak-day  would  amount to  approximately
1,999 MDTH. For the 2001/2002 winter season, KEDNY and KEDLI estimate that their
peak-day  requirements  will  amount  to 1,982  MDTH  and that the gas  supplies
available  to KEDNY and KEDLI on such a peak-day  will  amount to  approximately
1,999 MDTH.

For the 2000/2001  winter season,  the highest daily throughput to our customers
was 1,597 MDTH, which occurred on December 25, 2000 at an average temperature of
17(degree)F,  representing  80% of our capability at that time.  KEDNY and KEDLI
had  sufficient  gas  available  to meet  the  requirements  of  their  firm gas
customers  for the  2000/2001  winter gas season and  anticipate  they will have
sufficient  quantities for the 2001/2002  winter season.  KEDNY and KEDLI's firm
gas peak-day capability is summarized in the following table:


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

Pipeline..................                  716                         36
Underground Storage.......                  779                         39
Peaking Supplies..........                  504                         25
                                  -----------------------      -----------------
Total.....................                 1,999                       100
                                  =======================      =================

Pipelines and Storage.  KEDNY and KEDLI  purchase  natural gas for sale to their
customers under contracts with suppliers located in domestic and Canadian supply
basins and arranged for  transportation to their facilities under firm long-term
contracts  with  interstate  pipeline  companies.  During the  2000/2001  winter
season,  approximately  76% of  KEDNY's  and  KEDLI's  natural  gas  supply  was
available from domestic sources and 24% from Canadian  sources.  KEDNY and KEDLI
had available  under firm  contract 716 MDTH per day of year-round  and seasonal
pipeline  transportation  capacity  to their  facilities  in the New  York  City
metropolitan  area. Major providers of interstate  pipeline capacity and related
services to KEDNY and KEDLI include:  Transcontinental Gas Pipe Line Corporation
("Transco"),   Texas  Eastern  Transmission  Corporation  ("TETCO"),   Iroquois,
Tennessee  Gas Pipeline  Company  ("Tennessee"),  CNG  Transmission  Corporation
("CNG") and Texas Gas Transmission Company ("Texas").

Additionally,  KEDNY and KEDLI have  long-term  contracts  with Transco,  TETCO,
Tennessee,  CNG, Equitrans,  Inc., Hattiesburg First Reserve and Honeoye Storage
Corporation for underground  storage  capacity of 58,954 MDTH, with 779 MDTH per
day, maximum deliverability.

Peaking Supplies.  In our New York service territories,  in addition to pipeline
and storage supply,  KEDNY and KEDLI supplement their winter supply with peaking
supplies  which are  available on the coldest days of the year to enable them to
economically meet the increased  requirements of their heating customers.  KEDNY
and KEDLI's peaking supplies include gas provided by two of KeySpan's  liquefied
natural gas ("LNG") plants.  These LNG plants have an aggregate storage capacity
of approximately 2,053 MDTH and peak-day throughput capacity of 394 MDTH, or 20%
of peak-day supply. Additionally,  KEDNY and KEDLI have peaking supply contracts
with four


                                      -11-

<PAGE>



cogeneration  facilities/independent  power producers located in their franchise
areas: Trigen Services  Corporation,  Brooklyn Navy Cogeneration  Partners,  LP,
Nissequogue  Cogen Partners and the New York Power Authority to purchase peaking
supplies with a maximum daily capacity of 110 MDTH and total  available  peaking
supplies  during the  winter  season of 3,349  MDTH.  For the  2000/2001  winter
season,  KEDNY and KEDLI had the capability to provide a maximum peak-day supply
of 504 MDTH on excessively cold days.

Gas Supply  Management.  Commencing  April 1, 2000,  we entered  into a two-year
agreement  with Coral  Resources,  L.P.  ("Coral"),  in which Coral  assists our
wholly owned  subsidiary,  KeySpan  Energy  Trading  Services  LLC, in providing
energy supply management services for KEDNY and KEDLI. This agreement expires on
March 31, 2002. Additionally,  KeySpan Energy Trading Services LLC also provides
energy-management services undertaken on behalf of LIPA.

New England Gas Distribution Systems

Peak-Day  Capability.  The design criteria for KeySpan's New England gas systems
assumes  an  average  temperature  of -6(0)F  for  peak-day  demand.  Under such
criteria,  the KEDNE companies  estimated that the  requirements to supply their
firm  gas  customers  would  amount  to  approximately  1,217  MDTH of gas for a
peak-day  during the  2000/2001  winter season and that the gas available to the
KEDNE companies on such a peak-day would amount to approximately 1,321 MDTH. For
the 2001/2002  winter season,  the KEDNE companies  estimate that their peak-day
requirements  will amount to 1,240 MDTH and that the gas  supplies  available to
them on such a peak-day will amount to approximately 1,321 MDTH.

For the 2000/2001 winter season, the highest daily throughput to our New England
customers  was 980 MDTH,  which also occurred on December 25, 2000 at an average
temperature of 19(degree)F,  representing 74% of the KEDNE companies' capability
at that time.  The KEDNE  companies  had  sufficient  gas  available to meet the
requirements of their firm gas customers for the 2000/2001 winter gas season and
anticipate  that they will have sufficient  quantities for the 2001/2002  winter
season. The firm gas peak day capability of the KEDNE companies is summarized in
the following table:


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

Pipeline and Underground Storage....                  708                     54
Peaking Supplies....................                  613                     46
                                            -------------------    -------------
Total...............................                 1,321                   100
                                            ===================    =============

Pipelines and Storage. The KEDNE companies also purchase natural gas for sale to
their customers under contracts with suppliers  located in domestic and Canadian
supply  basins and arrange for  transportation  to their  facilities  under firm
long-term  contracts with interstate  pipeline  companies.  During the 2000/2001
winter season,  approximately 77% of the KEDNE companies' natural gas supply was
available  from  domestic  sources  and 23% from  Canadian  sources.  The  KEDNE
companies have available  under firm contract 708 MDTH per day of year-round and
seasonal


                                      -12-

<PAGE>



transportation  and  underground  storage  capacity to their  facilities  in New
England. Major providers of interstate pipeline capacity and related services to
the KEDNE companies include: TETCO, Iroquois,  Maritimes and Northeast Pipeline,
Tennessee,   Algonquin  Gas  Transmission   Company  and  Portland  Natural  Gas
Transmission System. Moreover, the KEDNE companies have long-term contracts with
TETCO,  Tennessee,  Dominion,  National Fuel Gas Supply  Corporation and Honeoye
Storage Corporation for underground storage capacity of 23,742 MDTH.

In our New England  service  territory,  in  addition  to  pipeline  and storage
supply, the KEDNE companies supplement their winter supply with peaking supplies
that  are  available  on the  coldest  days  of  the  year  to  enable  them  to
economically meet the increased requirements of their heating customers. Peaking
supplies  include  gas  provided  by both LNG and  propane  air  plants  located
throughout  the  distribution  systems  of the KEDNE  companies,  as well as two
leased facilities outside of their  distribution  systems located in Providence,
Rhode  Island  and  Everett,  MA. For the  2000/2001  winter  season,  the KEDNE
companies  had the  capability  to  provide  a  peak-day  supply  of 613 MDTH on
excessively cold days or 46% of peak-day supply.

Gas Supply Management.  Effective November 1, 1999, the Massachusetts  based gas
distribution   subsidiaries  entered  into  a  three-year  portfolio  management
contract with El Paso Energy  Marketing,  Inc. ("El Paso"). El Paso provides the
majority  of the  city  gate  supply  requirements  to the  three  Massachusetts
companies at market prices and manages upstream  capacity,  underground  storage
and term supply contracts.  The Massachusetts  Department of  Telecommunications
and Energy ("DTE") approved the contract in October 1999. The annual fee paid by
El Paso to manage the KEDNE companies' portfolio is, for the most part, returned
to firm customers.

Gas Costs. Fluctuations in utility gas costs have little impact on the operating
results  of KEDNY,  KEDLI  and  KEDNE  companies,  since  the  current  gas rate
structure of each of these  companies  includes a gas adjustment  clause whereby
variations  between  actual gas costs and gas cost  recoveries  are deferred and
subsequently refunded to or collected from customers.

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

                                Electric Services
Overview

KeySpan's  Electric  Services segment primarily consist of (i) the ownership and
operation of gas and oil fired generating  facilities located on Long Island and
New York and the delivery of the power  generated from these  facilities to LIPA
and the New York Independent System Operator ("NYISO");  (ii) the management and
operation  of  LIPA's  transmission  and  distribution  system;  and  (iii)  the
management of LIPA's fuel and electric energy purchases and off-system sales.

As more fully described below, we (i) provide to LIPA all operation, maintenance
and  construction  services  relating  to the Long  Island  electric  T&D system
through a  management  services  agreement  (the  "MSA");  (ii) supply LIPA with
energy conversion and ancillary services through a power supply


                                      -13-

<PAGE>



agreement  (the "PSA") to allow LIPA to provide  electricity to its customers on
Long Island; and (iii) manage all aspects of the fuel supply for the Long Island
generating  facilities,  as well as all aspects of the capacity and energy owned
by or under contract to LIPA through an energy management agreement (the "EMA").
Each  of the  MSA,  PSA  and  EMA  became  effective  on May  28,  1998  and are
collectively referred to herein as the "LIPA Agreements."

On June 18, 1999,  KeySpan  completed  its  acquisition  of the then rated 2,168
megawatt  Ravenswood  facility located in New York City from Consolidated Edison
Company  of New  York,  Inc.  ("Consolidated  Edison")  for  approximately  $597
million.  As a means of  financing  this  acquisition,  we entered  into a lease
agreement with a special purpose,  unaffiliated financing entity that acquired a
portion of the Ravenswood  facility directly from Consolidated Edison and leased
it to a  wholly  owned  KeySpan  subsidiary  under  a  ten-year  lease.  We have
guaranteed all payment and performance  obligations of this subsidiary under the
lease.  Another subsidiary provides all operating,  maintenance and construction
services for the Ravenswood facility. The lease program was established in order
to reduce our cash  requirements  by $425  million.  The lease  qualifies  as an
operating lease for financial  reporting purposes while preserving our ownership
of the facility for federal and state  income tax  purposes.  The balance of the
funds needed to acquire the Ravenswood facility were provided from cash on hand.

The  Ravenswood  facility  has  contributed  significantly  to earnings in 2000,
selling capacity,  energy and ancillary  services into the NYISO at market-based
rates, subject to mitigation. The plant, which provides approximately 25% of the
in-city capacity  available to serve residents and businesses during a period of
economic  growth,  underscores the value of electric  generation  assets for our
company.  We are in the process of expanding the Ravenswood facility by adding a
250-megawatt state-of-the- art gas-fired co-generation unit at the site which is
expected to come on line by 2003.

We currently sell the energy,  capacity and ancillary  services  produced by the
Ravenswood  facility by bidding into an auction process  conducted by the NYISO.
See Note 8 to the Consolidated  Financial Statements "New York State Independent
System Operator Matters" for further information.

Generating Facility Operations

KeySpan  owns  and  operates  an  aggregate  of  73  electric  generation  units
throughout Long Island and Queens,  40 of which can be powered either by natural
gas or oil. 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
such as adding water spray to smaller units, we increased  installed capacity in
our generating facilities by 37 megawatts, and we instituted a program to reduce
nitrogen oxides for improved environmental performance. Reliability improvements
at our Ravenswood facility reduced the forced outage rate for that facility from
35%  two  years  ago to just 5% in  2000.  Decreasing  the  amount  of time  our
generating  units are  offline for repair  allows us to increase  sales and thus
increase earnings.



                                      -14-

<PAGE>



The following table  indicates the 2000 summer capacity of our steam  generation
facilities and internal combustion ("IC") units as reported to the NYISO:

<TABLE>
<CAPTION>
       Location of Units                  Description                       Fuel                     Units                      MW
------------------------------- --------------------------------  ------------------------  ------------------------  --------------
<S>                                     <C>                               <C>                          <C>                 <C>
Long Island City                         Steam Turbine                     Dual*                         3                  1,736
Northport, L.I.                          Steam Turbine                     Dual*                         3                  1,166
Northport, L.I.                          Steam Turbine                      Oil                          1                    382
Port Jefferson, L.I.                     Steam Turbine                     Dual*                         2                    386
Glenwood, L.I.                           Steam Turbine                      Gas                          2                    231
Island Park, L.I.                        Steam Turbine                     Dual*                         2                    388
Far Rockaway, L.I.                       Steam Turbine                     Dual*                         1                    106
Long Island City                            IC Units                       Dual*                        17                    464
Throughout L.I.                             IC Units                       Dual*                        12                    290
Throughout L.I.                             IC Units                        Oil                         30                  1,088
------------------------------------------------------------------------------------------------------------------------------------
Total                                                                                                   73                  6,237
=============================== ================================  ========================  ========================  ==============
</TABLE>
*Dual - Oil or natural gas.

LIPA Agreements

Power  Supply  Agreement.  The PSA  provides  for the sale to LIPA of all of the
capacity  and,  to the  extent  LIPA  requests,  energy  from  the  Long  Island
generating  facilities.  Capacity  refers to the ability to generate energy and,
pursuant  to  NYISO  requirements,   must  be  maintained  at  specified  levels
(including  reserves) regardless of the source and amount of energy consumption.
By contrast,  energy  conversion  services  refers to the  electricity  actually
generated  for  consumption  by  consumers.  Such sales of  capacity  and energy
conversion services from the Long Island generating facilities are made at rates
regulated by the Federal Energy Regulatory Commission ("FERC").  These rates may
be modified in the future in accordance with the terms of the PSA for (i) agreed
upon labor and expense indices applied to the base year; (ii) a return of and on
the  capital  invested  in the Long  Island  generating  facilities;  and  (iii)
reasonably incurred expenses that are outside of our control.

The  PSA  provides  incentives  and  penalties  for us to  maintain  the  output
capability  of the Long  Island  generating  facilities,  as  measured by annual
industry-standard  tests of operating  capability,  and plant  availability  and
efficiency.  These  combined  incentives  and  penalties may total as much as $4
million annually. In 2000, KeySpan earned approximately $3 million in incentives
under the PSA.

The PSA provides LIPA with all of the capacity  from the Long Island  generating
facilities.  However,  LIPA has no  obligation  to  purchase  energy  conversion
services  from the Long  Island  generating  facilities  and is able to purchase
energy on a least-cost basis from all available sources consistent with existing
transmission  interconnection  limitations of the  transmission and distribution
system.  Under the terms of the PSA,  LIPA is  obligated  to pay for capacity at
rates which reflect a large  percentage of the overall fixed cost of maintaining
and  operating the Long Island  generating  facilities.  A variable  maintenance
charge is imposed for each unit of energy actually  generated by the Long Island
generating  facilities.  The PSA  expires on May 28,  2013 and is  renewable  on
similar terms.  However,  the PSA provides LIPA the option of electing to reduce
or "ramp-down" the capacity it purchases from us in accordance with  agreed-upon
schedules. In years 7 through 10 of the PSA, if LIPA elects to ramp-down, we are
entitled  to  receive  payment  for 100% of the  present  value of the  capacity
charges  otherwise  payable over the  remaining  term of the PSA. If LIPA ramps-
down the  generation  capacity in years 11 through 15 of the PSA,  the  capacity
charges  otherwise  payable by LIPA will be reduced in accordance with a formula
established in the PSA. If LIPA exercises its ramp-down option,  KeySpan may use
any capacity released by LIPA to bid on new LIPA capacity requirements or to bid
on LIPA's  capacity  requirements  to replace  other  ramped-down  capacity.  If
KeySpan  continues to operate the ramped-down  capacity,  the PSA requires it to
use  reasonable  efforts to market the capacity and energy from the  ramped-down
capacity and to share any profits with LIPA.  Any capacity and energy sold by us
from ramped-down  capacity must be transported over the T&D system,  and we will
be  required  to  pay  LIPA's   standard   transmission   (and,  if  applicable,
distribution)  rates for the service.  The PSA will be  terminated  in the event
that LIPA exercises its right to purchase, at fair market value, all of the Long
Island generating facilities. This purchase option commences on May 28, 2001 and
continues  for one year.  LIPA has  initiated  a process  to review  whether  to
exercise its right to purchase  the Long Island  generating  facilities  and has
begun soliciting proposals for the management,  operation and maintenance of the
Long Island generating facilities in the event it exercises its option.

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

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

In exchange for providing  these  services,  KeySpan is reimbursed  its budgeted
costs and entitled to earn an annual  management fee of $10 million and may also
earn certain incentives, or be responsible for certain penalties, based upon its
performance.  The incentives  provide for KeySpan to retain 100% of the first $5
million of cost  reductions and 50% of any additional  cost reductions up to 15%
of the total cost budget.  Thereafter,  all savings  accrue to LIPA.  KeySpan is
also  required 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,  KeySpan is
eligible for incentives for performance  above certain  threshold  target levels
and subject to disincentives for performance


                                      -15-

<PAGE>



below certain other threshold  levels,  with an intermediate band of performance
in  which  neither   incentives  nor   disincentives   will  apply,  for  system
reliability,  worker safety, and customer satisfaction.  In 2000, KeySpan earned
$7.4 million in non-cost performance incentives.

The MSA  continues in effect until May 28,  2006.  Beginning in 2004,  LIPA will
commence a competitive  process to solicit a new management  services agreement.
Generally,  KeySpan  will be  eligible  to  submit a bid for any new  management
services agreement.

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

In exchange for these  services,  KeySpan  earns 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  for control of the cost of fuel and
electricity  purchased on behalf of LIPA. Fuel and  electricity  purchase prices
are compared to regional price indices and we receive  payment from LIPA, or are
obligated to make payment to LIPA, for fuel and/or purchased  electricity  costs
which are below or above,  respectively,  specified  tolerance  bands. The total
fuel  purchase  incentive  or  disincentive  can be no  greater  than $5 million
annually  and the  electricity  purchase  incentive  or  disincentive  can be no
greater than $2 million  annually  (subject to an overall cap including  certain
non-cost performance  incentives under the MSA). For the year ended December 31,
2000, KeySpan earned an aggregate of $5 million in incentives under the EMA.

Other Rights. As described above, under a "Generation Purchase Rights Agreement"
entered into as part of the LIPA Transaction, LIPA has the right to purchase, at
fair market  value,  all of our Long Island based  generating  assets during the
twelve  month  period  beginning  on May 28,  2001.  Fair market  value is to be
determined pursuant to an appraisal process conducted by independent  investment
banking  firms.  During the fourth  quarter of 2000,  LIPA began an initial  due
diligence  review of the feasibility of purchasing these assets and has recently
solicited proposals from interested parties to operate the generating facilities
should they purchase  them.  At this point in time,  we can not predict  whether
LIPA will  exercise  its right to purchase  the assets,  nor can we estimate the
effect on our financial condition,  results of operations and cash flows if LIPA
were to exercise such right.

Pursuant to other  agreements  between LIPA and us,  certain  future rights have
been granted to LIPA.  Subject to certain  conditions,  these rights include the
right for 99 years to lease or purchase,  at fair market value,  parcels of land
and to acquire  unlimited  access to, as well as  appropriate  easements at, the
Long Island  generating  facilities for the purpose of constructing new electric
generating facilities to be owned by LIPA or its designee. Subject to this right
granted to LIPA, KeySpan has the right to sell or lease property on or adjoining
the Long Island generating facilities to third parties.


                                      -16-

<PAGE>



In  addition,  LIPA has the right to  acquire a parcel at the  Shoreham  Nuclear
Power Station site suitable as the terminus for a potential  transmission  cable
under Long Island Sound or the potential site of a new gas-fired  combined cycle
generating facility.

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

Guarantees and  Indemnities.  KeySpan and LIPA have also entered into agreements
providing  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.  KeySpan has 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 Long
Island generating  facilities and all liabilities  traceable to the business and
operations  conducted  by  LIPA  after  completion  of  the  1998  KeySpan/LILCO
transaction.  An agreement also provides for an allocation of liabilities  which
relate to the assets that were common to the  operations  of LILCO and/or shared
services and are not  traceable  directly to either the  business or  operations
conducted by LIPA or KeySpan.

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

                          Gas Exploration & Production

KeySpan is engaged in the exploration and production of domestic natural gas and
oil, through our approximate 70% equity interest in Houston  Exploration,  as of
the date hereof, and through our wholly owned subsidiary, KeySpan Exploration.

Houston  Exploration was organized by KeySpan in 1985 to conduct natural gas and
oil  exploration  and  production  activities.  It completed  an initial  public
offering  in 1996 and its  shares  are  currently  traded on the New York  Stock
Exchange  under  the  symbol  "THX."  At March 1,  2001,  its  aggregate  market
capitalization was approximately $898.7 million (based upon the closing price on
the New York Stock Exchange on that date of $29.97).  At March 1, 2001,  Houston
Exploration had approximately 29,987,041 shares of common stock, $.01 par value,
outstanding. More detailed


                                      -17-

<PAGE>



information concerning the operations of Houston Exploration is contained in the
annual,  quarterly and periodic  reports filed by Houston  Exploration  with the
SEC.

KeySpan   Exploration  was  organized  in  1999,  as  a  Delaware   corporation,
principally to form a joint venture with Houston Exploration.  Effective January
1, 1999,  KeySpan  Exploration  and  Houston  Exploration  entered  into a joint
exploration  agreement (the "Joint  Venture") to explore for natural gas and oil
over a term of three years and expiring on December 31, 2001, subject to earlier
termination at the option of either party.  Houston Exploration  contributed all
of its then  undeveloped  offshore  leases to the  Joint  Venture,  and  KeySpan
Exploration acquired a 45% working interest in all prospects to be drilled under
the Joint Venture.  Houston  Exploration  retained a 55% interest in the leases,
and the revenues  generated from this joint program are shared  between  KeySpan
Exploration  and  Houston  Exploration  on a 45%  and 55%  basis,  respectively.
Effective  December  31,  2000,  KeySpan  Exploration  and  Houston  Exploration
mutually agreed that KeySpan  Exploration  will no longer  participate in future
offshore exploration prospects.  Under the terms of the Joint Venture agreement,
KeySpan  Exploration will continue to maintain its working interest in all wells
previously  drilled under the Joint Venture and will continue the development of
its current  working  interests in prospects on which  discovery wells have been
drilled. In that regard,  KeySpan Exploration has agreed to commit approximately
$17 million during 2001 for the development of prospects successfully drilled by
the Joint Venture during 1999 and 2000.

In February  2000,  after  completing  a review of  strategic  alternatives  for
Houston Exploration, we concluded that we would, at this time, retain our equity
interest in that company.  However, as previously indicated, we consider our gas
and oil  exploration and production  activities to be non-core  operations and a
future disposition of these assets, for appropriate consideration, is possible.

As  previously  mentioned,  On  March  31,  2000,  under a  pre-existing  credit
arrangement, approximately $80 million in debt owed by Houston Exploration to us
was converted into additional  common equity in Houston  Exploration.  Upon such
conversion,   our  common  equity  ownership  interest  increased  from  64%  to
approximately 70%.

Our gas exploration and production  subsidiaries focus their operations offshore
in the Gulf of Mexico and onshore in South Texas,  South  Louisiana,  the Arkoma
Basin,  East Texas and West Virginia.  The geographic  focus of these operations
enables  our  subsidiaries  to  manage a  comparatively  large  asset  base with
relatively  few  employees and to add and operate  production at relatively  low
incremental  costs.  Our gas  exploration  and production  subsidiaries  seek to
balance  their  offshore and onshore  activities so that the lower risk and more
stable production  typically  associated with onshore properties  complement the
high potential  exploratory projects in the Gulf of Mexico by balancing risk and
reducing  volatility.  Houston  Exploration's  business  strategy  is to seek to
continue to increase reserves,  production and cash flow by pursuing  internally
generated prospects,  primarily in the Gulf of Mexico, by conducting development
and  exploratory  drilling on our offshore and onshore  properties and by making
selective opportune acquisitions.

Offshore Properties. We hold interests in 106 lease blocks, representing 543,816
gross (442,548 net) acres, in federal and state waters in the Gulf of Mexico, of
which 32 have  current  operations.  Houston  Exploration  operates  22 of these
blocks, accounting for approximately 80% of our offshore


                                      -18-

<PAGE>



production.  Over the past five years, we have drilled 28 successful exploratory
wells and 17 successful development wells in the Gulf of Mexico,  representing a
historical  success rate of 69%.  During  2000,  Houston  Exploration  drilled 8
successful  exploratory wells and 6 successful  development wells on its Gulf of
Mexico properties. The Joint Venture participated in 10 of the successful wells,
all 8 exploratory wells and 2 of the development wells.

Onshore  Properties.  We  also  own  onshore  natural  gas  and  oil  properties
representing  interests in 1,242 gross (844.1 net) wells,  approximately  85% of
which Houston  Exploration is the operator of record, and 175,320 gross (109,657
net) acres.  Over the past five years,  we have drilled or  participated  in the
drilling of 140 successful  development wells and 7 successful exploratory wells
onshore,  representing a historical success rate of 84%, through our interest in
Houston  Exploration.  During  2000,  Houston  Exploration  participated  in the
drilling of 44 successful development wells and 1 successful exploratory well on
its onshore properties.  During the same period,  Houston Exploration drilled or
participated in the drilling of 4 development wells that were not successful.

We did not acquire any onshore properties during 2000. Houston Exploration plans
to drill 4 onshore exploratory wells and 40 onshore development wells in 2001.

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


                                 Energy Services

As part of our  business  strategy,  we will  continue  to develop  and grow our
energy services  activities through our non-regulated  subsidiaries.  The Energy
Services segment provides services to customers located within the New York City
metropolitan area, New Jersey, Connecticut,  Massachusetts, New Hampshire, Rhode
Island and  Pennsylvania  through various  subsidiaries  which operate under the
following  four principal  lines of business:  (i) home energy  services,  which
provides residential and small commercial customers with service and maintenance
of energy systems and appliances,  as well as the  competitive  retail supply of
natural gas and electricity to residential and small commercial customers;  (ii)
business  solutions,  which provides  engineering,  consulting and  construction
services, services related to the design, construction, installation, operation,
maintenance and management of heating,  cooling and power  production  equipment
and systems, including ventilating, air conditioning,  electrical power, motors,
pumps, lighting, water, wastewater,  plumbing, piping, fire suppression systems,
for commercial  and  industrial  customers,  as well as the  competitive  retail
supply of natural gas and  electricity to large  commercial,  institutional  and
industrial  customers.  Certain  subsidiaries  within this line of business also
engage or may engage in the financing and ownership of cogeneration, small power
production,  thermal energy, chilled water and related equipment and facilities;
(iii) commodity procurement,  which provides management and procurement services
for fuel supply and management of energy sales, primarily for and from the


                                      -19-

<PAGE>



Ravenswood  facility,  as well as provides wholesale gas and electric purchasing
and  management  services;  and (iv) fiber optic  services in which we construct
fiber optic systems and facilities and own and lease fiber optic cable to local,
long  distance,  and  trans-Atlantic  carriers,  as  well  as  internet  service
providers.

Other energy  services that we are engaged in include  energy  related  internet
activities, microturbines and fuel cells.

Internet Activities.  During 2000, we launched the myHomeKey.com portal. Through
our exclusive  arrangement with  myHomeKey.com,  we created alliances with other
businesses to create a source for a wide array of home products and services, as
well as individualized community information.  MyHomeKey provides customers with
the ability to  electrically  manage a myriad of household tasks by linking them
with quality service providers,  allowing on-line scheduling of home repairs and
maintenance,  convenient  shopping for home  appliances,  one-stop  shopping for
utility services and access to energy saving equipment and systems.
Alternative  Generation  Technologies.  KeySpan is also  engaged in  alternative
generation  technologies  such  as  microturbines.   In  2000,  we  successfully
installed  the first  microturbine  unit on Long Island at the  Atlantis  Marine
World Aquarium. The unit, which runs on natural gas, produces up to 28 kilowatts
of  electricity  for the aquarium and uses its exhaust heat to provide hot water
to the facility's shark tank.

KeySpan expanded its energy services  operations through the acquisition of four
additional  companies located in the New York City metropolitan  area. The newly
acquired companies specialize in engineering-consulting, plumbing and mechanical
contracting  and  HVAC  contracting.  Additionally,  Eastern  and ENI  each  had
unregulated energy services  operations in Massachusetts and New Hampshire which
have expanded our energy  services  operations  further into the Northeast.  The
Energy Services  segment now has more than 3,000  employees,  100,000  commodity
contracts and is the number one oil to gas conversion  contractor in its service
territories.

KeySpan's energy services  operations  compete with the marketing and management
operations  of both  independent  and major  energy  companies  in  addition  to
electric utilities,  independent power producers,  local distribution  companies
and various energy brokers.  As a result of the continuing efforts to deregulate
both  the  natural  gas  and  electric  industries,  the  relative  energy  cost
differences  among  different  forms of energy are expected to be reduced in the
future. Competition is based largely upon pricing,  availability and reliability
of  supply,   technical  and  financial  capabilities,   regional  presence  and
experience. With our strong market presence in the Northeast centered on our gas
distribution  services and by taking  advantage of the increasing  trend towards
deregulation,  KeySpan  believes it is well  positioned to provide our customers
with an expanded array of energy  products and services  through our unregulated
energy service companies.

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



                                      -20-

<PAGE>



                               Energy Investments

As one of our complementary non-core lines of business,  KeySpan has investments
in certain  energy related  businesses,  including  natural gas  pipelines,  gas
storage facilities and midstream natural gas processing and gathering facilities
in the Northeast region of the United States, Canada and Northern Ireland.

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

KeySpan also is participating in two intra-regional pipeline projects, the Cross
Bay Pipeline and the Islander  East  Pipeline.  The Cross Bay Pipeline  Company,
LLC, is a joint venture among Duke Energy  Corporation,  The Williams  Companies
and KeySpan to transport 125 MDTH of gas from two existing interstate  pipelines
located in New  Jersey to  customers  located in New York City and Long  Island.
KeySpan  has a 25%  interest in this  project.  Additionally,  in 2000,  KeySpan
entered into another  joint  venture  with Duke to construct  the Islander  East
Pipeline.  KeySpan and Duke each hold a 50% interest in Islander  East  Pipeline
Company,  LLC, which will bring 250 MDTH of gas from Nova Scotia, Canada to Long
Island,  New York and will provide an  additional  connection to supplies in our
New  England  market.   The  Islander  East  Pipeline  is  scheduled  to  become
operational in 2003.

KeySpan  also  owns a 50%  interest  in  Premier  Transco  Pipeline  and a 24.5%
interest in Phoenix Natural Gas Limited both in Northern Ireland.  Premier is an
84-mile  pipeline to Northern  Ireland from southwest  Scotland that has planned
transportation capacity of approximately 300 MDTH of gas supply daily to markets
in Northern  Ireland.  Phoenix is a gas distribution  system serving the City of
Belfast, Northern Ireland.

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

Natural Gas  Processing  and  Gathering  Facilities.  KeySpan  also owns 100% of
KeySpan  Canada,  a company with  natural gas  processing  plants and  gathering
facilities  located in Western Canada.  In October 2000,  KeySpan  purchased the
remaining 50% interest in KeySpan Canada from Gulf Canada Resources Limited. The
assets  include  interests  in 14  processing  plants and  associated  gathering
systems  that can  process  approximately  1.5 BCFe of natural  gas  daily,  and
associated natural gas liquids fractionation.  Additionally,  KeySpan owns a 37%
interest in the Paddle River  processing plant in Western Canada and an interest
in the Younger NGL Extraction plant in British


                                      -21-

<PAGE>



Columbia,  Canada. In 2000, KeySpan sold its interest in the Nipisi oil property
in Western Canada,  and realized an after-tax gain of approximately $1.3 million
from the sale.

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


                    The Industry, Regulation and Rate Matters

The Industry

The  natural gas and  electric  sectors of the  regulated  energy  industry  are
undergoing  significant  change as market forces are moving towards replacing or
supplementing  rate  regulation  by  introducing  competition.  Competition  can
present utilities with greater opportunities to manage the cost of their natural
gas and  electric  supplies,  as well as earn profits on energy sales and expand
their business activities, through unregulated affiliates.

A significant  number of natural gas and electric  utilities have 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 have engaged in two such  combinations,
the KeySpan/LILCO transaction in 1998 and our recent acquisitions of Eastern and
ENI. For further information  regarding the gas and electric industry,  see Item
7A, Quantitative and Qualitative Disclosure About Market Risk.


Regulation and Rate Matters

Gas and electric public utility  companies,  and corporations  which own gas and
electric public utility companies (i.e.,  public utility holding  companies) may
be subject to either or both state and federal  regulation.  In  general,  state
public  utility  commissions,  such as the  NYPSC,  DTE and NHPUC  regulate  the
provision of retail services, including the distribution and sale of natural gas
and   electricity   to  consumers.   FERC  regulates   interstate   natural  gas
transportation  and electric  transmission,  and has  jurisdiction  over certain
wholesale natural gas sales and wholesale electric sales. Public utility holding
companies,  especially those with operations in several states, are regulated by
the SEC under PUHCA and to some extent by state utility  commissions through the
regulation of corporate, financial and affiliate activities of public utilities.

KeySpan and its subsidiaries are subject to regulation by the NYPSC, DTE, NHPUC,
FERC and the SEC. The NYPSC  regulates KEDNY and KEDLI,  and indirectly  KeySpan
itself,  through  conditions which were attached to the NYPSC order  authorizing
the 1998  KeySpan/LILCO  transaction.  The NYPSC also  regulates  the safety and
reliability of KeySpan's generating  facilities on Long Island and at Ravenswood
under a lightened regulatory standard. Those conditions addressed the manner


                                      -22-

<PAGE>



in which  KeySpan  may  interact  with  KEDNY and KEDLI.  Similarly,  we are now
subject to regulation by the DTE and NHPUC for our KEDNE subsidiaries.

For information  regarding the NYPSC, DTE and SEC, see the discussion in Item 7,
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations, "Regulation and Rate Matters."

FERC  regulates the sale of  electricity  at wholesale and the  transmission  of
electricity  in interstate  commerce as well as certain  corporate and financial
activities  of companies  that are engaged in such  activities.  The Long Island
generating facilities and the Ravenswood facility are subject to FERC regulation
based on their wholesale  energy  transactions.  LIPA,  KeySpan and the Staff of
FERC stipulated a five-year rate plan for the Long Island generating  facilities
with  agreed-upon  yearly  adjustments,  which has been  approved  by FERC.  Our
Ravenswood  facility's  rates  are  based  on a  market-based  rate  application
approved by FERC. The rates that our Ravenswood  facility may charge are subject
to mitigation  measures due to market power  concerns of FERC.  FERC retains the
ability  in future  proceedings,  either on its own  motion or upon a  complaint
filed with FERC, to modify the  Ravenswood  facility's  rates,  either upward or
downward, if FERC concludes that it is in the public interest to do so.

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, KEDNE purchase or sell gas for resale
in interstate  commerce,  such transactions are subject to FERC jurisdiction and
have been authorized by the FERC.

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

KeySpan's electric  operations in New York City are also subject to oversight by
the FERC approved  NYISO.  KeySpan  currently bids and sells the energy capacity
and ancillary  services from the Ravenswood  facility  through the energy market
operated by the NYISO.  For information  concerning the NYISO, see Note 8 to the
Consolidated  Financial  Statements,   "New  York  Independent  System  Operator
Matters."

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



                                      -23-

<PAGE>



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


                              Environmental Matters

Overview

KeySpan's ordinary business operations subject it to various federal,  state and
local laws, rules and regulations  dealing with the environment,  including air,
water, and hazardous waste, and its business operations are regulated by various
federal,  regional,  state and local. These requirements govern both our normal,
ongoing operations and the remediation of contaminated  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 9 to the Consolidated Financial Statements
"Contractual Obligations and Contingencies - Environmental Matters", no material
proceedings  relating to  environmental  matters have been  commenced or, to our
knowledge,  are  contemplated  by any  federal,  state or local  agency  against
KeySpan,  and we are not a defendant in any material  litigation with respect to
any matter  relating to the protection of the  environment.  We believe that our
operations  are in  substantial  compliance  with  environmental  laws  and that
requirements  imposed  by  environmental  laws are not likely to have a material
adverse  impact  upon us.  We  believe  that all  prudently  incurred  costs not
recoverable  through insurance or some other means with respect to environmental
requirements will be recoverable from our customers. We are also pursuing claims
against insurance  carriers and potentially  responsible  parties which seek the
recovery of certain costs associated with the  investigation  and remediation of
contaminated properties.

Air. Federal, state and local laws currently regulate a variety of air emissions
from new and existing electric  generating  plants,  including SO2, NOx, opacity
and particulate  matter and, in the future,  may also regulate emissions of fine
particulate  matter,  hazardous  air  pollutants,  and carbon  dioxide.  We have
submitted timely applications for permits in accordance with the requirements of
Title V of the 1990  amendments  to the  Federal  Clean Air Act  ("CAA").  Final
permits  have been issued for all of our  electric  generating  facilities.  The
permits allow our electric  generating plants to continue to operate without any
additional significant expenditures, except as described below.

Our generating  facilities are located within a CAA severe ozone  non-attainment
area,  and are  subject to the Phase I, II, and III NOx  reduction  requirements
established  under the Ozone  Transportation  Commission  ("OTC")  memorandum of
understanding. Our investments in boiler combustion modifications and the use of
natural gas firing at our steam electric  generating stations have enabled us to
achieve  the  NOx  emission  reductions  required  under  Phase  I  and  II in a
cost-effective  manner.  We are awaiting final  development of state and federal
regulatory programs with respect to NOx reduction  requirements for our existing
power plants. Our compliance  strategy may be composed of fuel choice decisions,
acquisition of emission credits, and installation of emission control


                                      -24-

<PAGE>



equipment.  The extent of  development of new generation in the region will also
impact our compliance  strategy.  Although we are  evaluating our  alternatives,
final decisions  cannot be made until pending  regulatory  requirements  and new
generation  decisions are clarified.  Expenditures to address emission reduction
requirements  through  the year 2004 are  expected to be between $10 million and
$15 million.

Water.  We possess permits for our generating  units which authorize  discharges
from cooling water circulating  systems and chemical  treatment  systems.  These
permits are renewed  from time to time,  as required by  regulation.  Additional
capital expenditures  associated with the renewal of the surface water discharge
permits for our power  plants may be required by the DEC.  Until our  monitoring
obligations  are completed and changes to the  Environmental  Protection  Agency
regulations  under Section 316 of the Clean Water Act are promulgated,  the need
for and the cost of equipment upgrades cannot be determined.

On  behalf  of LIPA,  we  provide  management  and  operations  support  for the
LIPA-Connecticut  Light and Power  Company  electric  transmission  cable system
located  under the Long  Island  Sound  (the  "Sound  Cable").  The  Connecticut
Department  of  Environmental  Protection  and the DEC  separately  have  issued
Administrative Consent Orders ("ACOs") in connection with releases of insulating
fluid from the Sound  Cable.  The ACOs  require  the  submission  of a series of
reports and studies  describing  cable system  condition,  operation  and repair
practices, alternatives for cable improvements or replacement, and environmental
impacts  associated  with  prior  leaks of fluid  into  the Long  Island  Sound.
Compliance  activities  associated with the ACOs are ongoing and are recoverable
from LIPA under the MSA.

In addition,  we will be responsible for environmental  obligations  relating to
the  Ravenswood   facility   operations  other  than  liabilities  arising  from
pre-closing  disposal  of waste at off-site  locations  and any  monetary  fines
arising from Consolidated Edison's pre-closing conduct.

Superfund  Sites.  Federal and New York State  Superfund laws impose  liability,
regardless  of  fault,  upon  generators  of  hazardous   substances  for  costs
associated with remediating contaminated property. In the course of our business
operations,  we generate materials which are subject to these laws. From time to
time, we have received notices under these laws concerning  possible claims with
respect to sites at which  hazardous  substances  generated by KeySpan and other
potentially responsible parties allegedly were disposed.

For further information concerning environmental matters and a discussion on our
MGP sites, see Note 9 to the  Consolidated  Financial  Statements,  "Contractual
Obligations and Contingencies - Environmental Matters."

Employee Matters

On  December  31,  2000,   KeySpan  and  its  wholly  owned   subsidiaries   had
approximately 13,000 employees. Of that total, approximately 6,5602 employees in
our  regulated  companies are covered under  collective  bargaining  agreements.
KeySpan has not experienced any work stoppage during


                                      -25-

<PAGE>



the past five years and considers its  relationship  with  employees,  including
those covered by collective bargaining agreements, to be good.

Executive Officers of the Company

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

Robert B. Catell

Mr.  Catell,  age 64, 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  served as President  and Chief  Executive
Officer  from 1991 to 1996,  when he was elected  Chairman  and Chief  Executive
Officer. In 1997, Mr. Catell was elected Chairman, President and Chief Executive
Officer of the KEDNY and its parent KSE.

Joseph A. Bodanza

Mr.  Bodanza,  age 53, was elected  Senior Vice  President  and Chief  Financial
Officer of KEDNE in November 2000,  upon the acquisition of Eastern and ENI. Mr.
Bodanza  previously  served as Senior Vice  President of Finance and  Management
Information Systems and Treasurer of Eastern's Gas Distribution Operations.  Mr.
Bodanza  joined  Boston  Gas in 1972  and held a  variety  of  positions  in the
financial and regulatory areas before becoming Treasurer in 1984. He was elected
Vice President and Treasurer in 1988.

Lawrence S. Dryer

Mr. Dryer,  age 41, was elected Vice  President of Internal Audit for KeySpan in
September  1998.  Mr.  Dryer had been with the LILCO  since 1992 as  Director of
Internal  Audit and was  responsible  for providing  independent  appraisals and
recommendations  to  improve  management   controls  and  increase   operational
efficiency.  Prior to joining LILCO, Mr. Dryer was an Audit Manager with Coopers
& Lybrand.

Robert J. Fani

Mr. Fani, age 47, was elected Executive Vice President of Strategic  Services in
February  2000.  Mr. Fani joined KEDNY in 1976, and held a variety of management
positions  in  distribution,  engineering,  planning,  marketing,  and  business
development.  He was  elected  Vice  President  in 1992.  In 1997,  Mr. Fani was
promoted to Senior Vice President of Marketing and Sales for KEDNY.  In 1998, he
assumed the position of Senior Vice  President  of  Marketing  and Sales for the
merged  KeySpan/LILCO  company.  On  September  1, 1999,  he became  Senior Vice
President for Gas  Operations  until  assuming his current  position in February
2000.



                                      -26-

<PAGE>



William K. Feraudo

Mr.  Feraudo,  age 51, was  elected  Executive  Vice  President  of the  KeySpan
Services  Group in  February  2000.  KeySpan  Services  Group,  is the  group of
non-regulated companies that engage in our energy services business and focus on
gas and  electric  marketing,  energy  management,  telecommunications  and fuel
procurement. Since its founding in 1996, the KeySpan Services Group has grown to
more than 3,000 employees, serving customers in the Northeast. Mr. Feraudo began
his  career  at KEDNY in 1971 and rose  through a  succession  of  positions  in
Information Systems,  Engineering,  Customer Operations,  Sales, Marketing,  and
Product  Development before being named Senior Vice President in 1994. He served
as Senior Vice  President of Energy  Services for KeySpan prior to his promotion
to Executive Vice President.

Ronald S. Jendras

Mr. Jendras,  age 53, was named Vice President,  Controller and Chief Accounting
Officer of KeySpan in August 1998. He joined KEDNY in 1969 and held a variety of
positions in the  Accounting  Department  before being named budget  director in
1973. In 1983,  Mr. Jendras was promoted to manager of KED's Rate and Regulatory
Affairs area, and in 1997, was named general manager of the Accounting Division.

Gerald Luterman

Mr Luterman,  age 57, has served as Senior Vice  President  and Chief  Financial
Officer  since July  1999.  He  formerly  served as Chief  Financial  Officer of
barnesandnoble.com  and Senior Vice  President  and Chief  Financial  Officer of
Arrow  Electronics,  Inc., a distributor  of electronic  components and computer
products.  Prior to that,  from 1985 through 1996, he held  executive  positions
with American  Express,  including  Executive Vice President and Chief Financial
Officer of the Consumer Card Division from 1991-1996.

David J. Manning

Mr.  Manning,  age 50, was elected  Senior Vice  President of KeySpan  Corporate
Affairs  division 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, the source of approximately 14 percent of the natural gas supply serving
United  States  markets.  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.

Craig G. Matthews

Mr. Matthews,  age 58, was elected as a Director and as Vice-Chairman  effective
March  2001.  He serves as Chief  Operating  Officer of KeySpan  and KEDNY since
January 1999,  and served as President of KeySpan until his recent  promotion to
Vice Chairman.  Mr.  Matthews  joined KEDNY in 1965 and held various  management
positions in the corporate planning, financial, marketing, and


                                      -27-

<PAGE>



engineering  areas.  He has been an officer  since  1977.  He was  elected  Vice
President in 1981 and Senior Vice President in 1985. In 1991,  Mr.  Matthews was
named Executive Vice President with responsibilities for KEDNY's financial,  gas
supply,  information  systems,  and  strategic  planning  functions,  as well as
KEDNY's  energy-related  investments.  In 1996,  Mr.  Matthews  was  promoted to
President  and  Chief  Operating  Officer.  He also  served  as  Executive  Vice
President and Chief  Financial  Officer of KeySpan from May 1998 through  August
1999.

Chester R. Messer

Mr. Messer,  age 59, was elected Executive Vice President in November 2000, upon
the  acquisition  of Eastern and ENI. He also serves as President of each of the
KEDNE companies. Mr. Messer joined Boston Gas Company as a management trainee in
1963 and rose through a succession  of  positions  and was elected  President in
November 1988.

H. Neil Nichols

Mr.  Nichols,  age 63, was elected Senior Vice President of KeySpan's  Corporate
Development  & asset  Management  division  in March  1999.  He also  serves  as
President of KeySpan Energy Development  Corporation (KEDC), a position to which
he was  elected in March  1998.  KEDC is a wholly  owned  subsidiary  of KeySpan
responsible  for our Energy  Investments  group that  engages in  energy-related
investment project development  efforts,  both domestically and internationally.
Since  February 1999,  Mr.  Nichols also has  responsibility  for KeySpan Energy
Trading  Services,  LLC, which provides fuel  procurement  management and energy
trading  services for KEDNY,  KEDLI and LIPA. Mr. Nichols joined KeySpan in 1997
as a broad-based  negotiator and business strategist with comprehensive  finance
and treasury experience in domestic and international  markets. Prior to joining
KeySpan, Mr. Nichols was an owner and president of Corrosion Interventions, Ltd.
in Toronto, Canada. He also served as Chief Financial Officer and Executive Vice
President with TransCanada.

Anthony Nozzolillo

Mr.  Nozzolillo,  age 52, 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.  He served as Senior  Vice  President  of
Finance of KeySpan from May 1998 to December  1998. He also serves as a Director
to the Long Island Museum of Science and Technology.

Wallace P. Parker Jr.

Mr.  Parker,  age 51, was elected  Executive Vice President of Gas Operations in
February 2000. He previously  served as KeySpan's Senior Vice President of Human
Resources  from August 1998 to January  2000. He joined KEDNY in 1971 and served
in a wide variety of management positions.


                                      -28-

<PAGE>



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.

Lenore F. Puleo

Ms. Puleo,  age 47, was elected  Executive Vice President of Shared  Services in
February  2000.  She  previously  served as Senior  Vice  President  of Customer
Relations for KEDNY from May 1994 to May 1998,  and for KeySpan from May 1998 to
January  2000.  She joined KEDNY in 1974 and worked in  management  positions in
KEDNY 's Accounting,  Treasury,  Corporate Planning,  and Human Resources areas.
She was given  responsibility for the Human Resources Department in 1987 and was
named a Vice  President in 1990. Ms. Puleo was promoted to Senior Vice President
of KEDNY 's Customer Relations in 1994.

Richard A. Rapp, Jr.

Mr.  Rapp,  age 42, was elected Vice  President  and Deputy  General  Counsel in
February  2000 and in June 2000,  he assumed the  additional  responsibility  of
Secretary.  He joined LILCO in 1984 and has held various  positions in the Legal
Departments  of LILCO,  and since 1998,  KeySpan,  including  Assistant  General
Counsel.  Mr. Rapp  received a Bachelor  of Science  degree in  Accounting  from
Boston College's Carroll School of Management's  Honors Program,  and he holds a
Juris Doctor degree from Fordham University's School of Law.

Cheryl T. Smith

Ms. Smith,  age 49, joined  KeySpan in November  1998. She serves as Senior Vice
President  and Chief  Information  Officer of KeySpan's  Information  technology
division.  She came to KeySpan from Verizon (Bell  Atlantic) where she served as
Vice  President of  Strategic  Systems and  Corporate  Systems from 1995 through
1998. Prior to Bell Atlantic,  she worked at Honeywell Federated Systems Inc. as
the  Director of MIS for  Honeywell  Federal  Systems,  Inc. Ms. Smith brings to
KeySpan more than 25 years of information systems technology experience.

Michael J. Taunton

Mr. Taunton,  age 45, has been KeySpan's Vice President and Treasurer since June
2000.  Prior to that time,  he served as Vice  President  of Investor  Relations
since  September  1998.  He  joined  KEDNY in 1975  and has  worked  in  various
management  positions  in Marketing  and Sales,  Corporate  Planning,  Corporate
Finance  and  Accounting.  During the  transition  process of the  KeySpan/LILCO
merger, he co-managed the day-to-day  operations of the merger. Before that, Mr.
Taunton was General Manager of the Business Process  Improvement teams that were
organized to improve the organization's strategic focus.

Colin P. Watson

Mr.  Watson,  age 49, was named Senior Vice  President  of  KeySpan's  Strategic
Marketing and E-Business  division effective March 1, 2000. He previously served
as Vice President of Strategic


                                      -29-

<PAGE>


Marketing from May 1998 until his promotion to Senior Vice President.  Mr Watson
joined  KEDNY in 1997 as Vice  President of  Strategic  Marketing.  From 1973 to
1997, he held several positions at NYNEX,  including Vice President and Managing
Director of worldwide operations.

Elaine Weinstein

Ms.  Weinstein,  age 46, was named  Senior Vice  President  of  KeySpan's  Human
Resources  division in November 2000. She previously served as Vice President of
Staffing  Organizational  Development  since September 1998. Prior to that time,
Ms. Weinstein was General Manager of Employee  Development since joining KeySpan
in 1995.  Prior to 1995,  Ms.  Weinstein  was Vice  President  of  Training  and
Organizational Development at Merrill Lynch.

Steven L. Zelkowitz

Mr. Zelkowitz,  age 51, was elected Senior Vice President and General Counsel of
KeySpan in February  2000. He joined KeySpan as Senior Vice President and Deputy
General  Counsel in October  1998.  Before  joining the Company,  Mr.  Zelkowitz
practiced  law with  Cullen  and  Dykman  in  Brooklyn,  New York and had been a
partner since 1984. He served on the firm's Executive  Committee and was head of
its Corporate/Energy Department. Mr. Zelkowitz specialized in energy and utility
law and represented  investor-owned  and municipal gas and electric utilities in
New York, New Jersey and Vermont.




                                      -30-

<PAGE>

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 oil and gas 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 owns or leases a variety of office space used for its
administrative  operations. 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 relating to our
leased properties.

Item 3.  Legal Proceedings

See Note 9 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, 2000.

                                     PART II

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

KeySpan's  common stock is listed and traded on the New York Stock  Exchange and
the Pacific Stock  Exchange  under the symbol "KSE." As of March 1, 2001,  there
were  approximately  88,640 registered record holders of KeySpan's common stock.
The following  table sets forth,  for the quarters  indicated,  the high and low
sales prices and dividends declared per share for the periods indicated:
<TABLE>
<CAPTION>

2000                              High                 Low                Dividends Per Share
--------------------------  ---------------  ---------------------  -------------------------
<S>                            <C>                  <C>                           <C>
First Quarter                   27.188               20.188                        $0.445
Second Quarter                  32.688               26.000                        $0.445
Fourth Quarter                  43.625               33.500                        $0.445


1999                              High                 Low                Dividends Per Share
-------------------------  ----------------  ---------------------  -------------------------
First Quarter                   31.313               25.125                        $0.445
Second Quarter                  27.690               24.250                        $0.445
Third Quarter                   31.060               26.380                        $0.445
Fourth Quarter                  29.690               22.630                        $0.445
</TABLE>



<PAGE>


Item 6.  Selected Financial Data
<TABLE>
<CAPTION>
                                                                                 (In Thousands of Dollars, Except Per Share Amounts)
------------------------------------------------------------------------------------------------------------------------------------
                                                                                   Nine Months                         Twelve Months
                                          Year Ended          Year Ended            Ended              Year Ended          Ended
                                      December 31, 2000    December 31, 1999    December 31, 1998    March 31, 1998   March 31, 1997
------------------------------------------------------------------------------------------------------------------------------------
<S>                                      <C>                 <C>                <C>                  <C>                <C>
Income Summary
Revenues
Gas Distribution                       $  2,555,785       $    1,753,132      $    856,172    $          645,659     $     672,705
Electric Services                         1,444,711              861,582           408,305                     -                 -
Electric Distribution                             -                    -           330,011             2,478,435         2,464,957
Gas Exploration and Production              274,209              150,581            70,812                     -                 -
Energy Services and Other                   846,785              189,318            63,181                     -                 -
------------------------------------------------------------------------------------------------------------------------------------
Total revenues                            5,121,490            2,954,613         1,728,481             3,124,094         3,137,662
Operating expenses
Purchased gas                             1,408,621              744,432           331,690               299,469           308,400
Fuel and purchased power                    460,900               17,252            91,762               658,338           646,448
Operation and maintenance                 1,695,507            1,091,166           777,678               511,165           489,868
Depreciation, depletion and
    amortization                            335,106              253,440           254,859               183,129           276,615
Early retirement and
    severance charges                        65,175                    -            64,635                     -                 -
General taxes                               424,318              366,154           257,124               466,326           469,561
------------------------------------------------------------------------------------------------------------------------------------
Operating income                            731,863              482,169           (49,267)            1,005,667           946,770
Other income (deductions)                   (11,430)              46,555           (36,727)               (6,301)           22,191
------------------------------------------------------------------------------------------------------------------------------------
Income (loss) before interest
charges and  income taxes                   720,433              528,724           (85,994)              999,366           968,961
Interest charges                            203,350              133,751           140,733               404,473           435,219
Income taxes (credits)                      216,276              136,362           (59,794)              232,653           211,333
------------------------------------------------------------------------------------------------------------------------------------
Net income (loss)                           300,807              258,611          (166,933)              362,240           322,409
Preferred stock dividends                    18,113               34,752            28,604                51,813            52,113
------------------------------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock       $    282,694       $      223,859      $   (195,537)    $         310,427     $     270,296
------------------------------------------------------------------------------------------------------------------------------------
Financial Summary
Earnings (loss) per share ($)                  2.10                 1.62             (1.34)                 2.56              2.24
Cash dividends declared per share ($)          1.78                 1.78              1.19                  1.78              1.78
Book value per share, year-end ($)            20.65                20.26             20.90                 21.88             21.07
Market value per share, year-end ($)          42.38                23.19             31.00                 31.50             24.00
Shareholders                                 86,900               90,500           103,239                78,314            77,691
Capital expenditures ($)                    925,257              725,670           676,563               297,230           294,943
Total assets ($)                         11,550,121            6,730,691         6,895,102            11,900,725        11,849,574
Common equity ($)                         2,815,816            2,712,325         3,022,908             2,662,447         2,549,049
Redeemable preferred stock ($)                    -              363,000                 -               562,600           638,500
Preferred stock ($)                          84,205               84,339           447,973                     -            63,598
Long term debt ($)                        4,274,938            1,682,702         1,619,067             4,381,949         4,457,047
Total capitalization ($)                  7,174,959            4,479,366         5,089,948             7,606,996         7,708,194
------------------------------------------------------------------------------------------------------------------------------------
Utility Operating Statistics
Firm gas and transportation
      sales (MDTH)                          306,509              275,771            87,179                58,304            60,276
Other sales (MDTH)                           91,406               54,661            38,088                21,025            19,838
Total active gas meters                   2,483,730            1,628,497         1,610,202               464,563           458,910
Gas heating customers                     1,260,000              677,000           665,000               295,000           289,000
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


<PAGE>


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

KeySpan Corporation (referred to in this Management's Discussion and Analysis of
Financial  Condition and Results of Operations as  "KeySpan",  "we",  "us",  and
"our") is a registered  holding company under the Public Utility Holding Company
Act of 1935, as amended. We operate six utilities that distribute natural gas to
approximately 2.4 million customers in New York City, Long Island, Massachusetts
and New Hampshire  making us the fifth largest gas  distribution  company in the
United  States  and  the  largest  in the  Northeast.  We also  own and  operate
generating  plants in Nassau and  Suffolk  Counties on Long Island and in Queens
County in New York City.  Under  contractual  arrangements,  we  provide  power,
electric  transmission  and  distribution  services,  billing and other customer
services for  approximately  one million  electric  customers of the Long Island
Power Authority  ("LIPA").  Our other  subsidiaries  are involved in gas and oil
exploration and production;  gas storage;  wholesale and retail gas and electric
marketing;   appliance  service;  heating,   ventilation  and  air  conditioning
installation  and services;  large  energy-system  ownership,  installation  and
management;  engineering services; fiber optic services; energy-related internet
activities;  fuel cells; marine  transportation,  including the barge hauling of
fuel and other cargo;  and  providing  meter  reading  equipment and services to
municipal  utilities.  We also invest in, and participate in the development of,
pipelines and other energy-related  projects,  domestically and internationally.
(See Note 2 to the Consolidated  Financial  Statements,  "Business Segments" for
additional information on each operating segment.)

KeySpan was formed on May 28, 1998 in connection with a transaction between Long
Island  Lighting  Company  ("LILCO")  and  LIPA  (the  "LIPA  Transaction")  and
immediately  prior to the  acquisition  (the "KeySpan  Acquisition")  of KeySpan
Energy Corporation ("KSE") and its subsidiaries (collectively, the "KSE-acquired
companies").  (See Note 15 to the Consolidated  Financial  Statements,  "Sale of
LILCO Assets,  Acquisition of KeySpan Energy  Corporation and Transfer of Assets
and Liabilities to KeySpan" for additional information.)

Further,  on  November  8, 2000,  KeySpan  acquired  all of the common  stock of
Eastern Enterprises ("Eastern") and EnergyNorth,  Inc. ("ENI"). The transactions
were  accounted for as a purchase,  with KeySpan  being the  acquiring  company.
Eastern  is a  Massachusetts  business  trust  that owns  primarily  Boston  Gas
Company,  Colonial Gas Company, Essex Gas Company and Midland Enterprises,  Inc.
ENI is a holding company that owns primarily EnergyNorth Natural Gas, a provider
of gas  distribution  services to customers in New Hampshire.  In the aggregate,
our newly acquired  subsidiaries  provide  natural gas  distribution  service to
approximately 800,000 customers in Massachusetts and New Hampshire. (See Note 12
to the Consolidated Financial Statements,  "Eastern/EnergyNorth Acquisition" for
further details.)





                                        1

<PAGE>



Current  period  consolidated  results  of  operations  reflect  the  results of
operations for Eastern and ENI for the period November 8, 2000 through  December
31, 2000. As required under purchase accounting,  reported results of operations
for all periods prior to November 8, 2000 do not reflect the  operating  results
of Eastern and ENI.

In 1998,  KeySpan  changed  its fiscal  year end from March 31 to  December  31.
Therefore,  results of operations for the period ended December 31, 1998 reflect
the nine  month  transition  period  April 1,  1998 to  December  31,  1998 (the
"Transition Period").  The Transition Period consists of the following:  (i) the
period April 1, 1998 through May 28, 1998,  which  reflects the results of LILCO
only prior to the LIPA Transaction and KeySpan Acquisition;  and (ii) the period
May 29, 1998 through  December 31, 1998,  which  represents  fully  consolidated
results,  including  the  KSE-acquired  companies,  i.e. The Brooklyn  Union Gas
Company  d/b/a  KeySpan  Energy  Delivery New York  ("KEDNY")  and  subsidiaries
comprising  the Gas  Exploration  and  Production,  Energy  Services  and Energy
Investment  segments.  As required  under  purchase  accounting,  the results of
operations for all periods prior to May 29, 1998 reflect  results of LILCO only,
and do not include results of KSE, since for accounting purposes, LILCO acquired
KSE as of May 29, 1998.

Due to the change in the  composition  of our  operations  and the change in our
fiscal year,  both  occurring in 1998,  results of operations for the Transition
Period are not  comparable  to the  results of  operations  for the years  ended
December  31, 2000 and  December 31, 1999.  Also,  since the  Transition  Period
reflects  results  for the  period  April 1, 1998  through  December  31,  1998,
earnings  from gas  heating-season  operations  are not  reflected in Transition
Period results.  Approximately 80% of our gas distribution-related  earnings, or
approximately 40% of our consolidated  earnings,  are realized during the months
of January  through March,  due to the large  percentage of gas heating sales to
total gas sales.

Since the  Transition  Period is not  comparable to the years ended December 31,
2000 and December  31, 1999,  we have  provided  operating  results for the full
twelve months ended December 31, 1998 in our  discussions  of operating  results
for each  business  segment.  The  intent of this  additional  disclosure  is to
provide a better  explanation  of the  variations in operating  results  between
comparable  twelve month  periods for our  on-going  business  activities.  (See
"Segment Review of Operations - Combined Company Comparison.")

The commentary that follows should be read in conjunction  with the Notes to the
Consolidated Financial Statements.








                                        2

<PAGE>



Consolidated Review of Results
------------------------------

Earnings Summary

Consolidated  income (loss)  available for common stock by reporting  segment is
set forth in the following table for the periods indicated:

<TABLE>


                                                                                                         (In Thousands of Dollars)
----------------------------------------------------------------------------------------------------------------------------------
                                      Year Ended December 31, 2000                       April 1, 1998 through December 31, 1998
                       ---------------------------------------------                 ---------------------------------------------
<CAPTION>
                       Before Early
                        Retirement         Early        After Early
                            and         Retirement     Retirement and   Year Ended     Before Early       Early       After Early
                         Severance     and Severance     Severance     December 31,     Retirement     Retirement      Retirement
                          Charges         Charges         Charges          1999           Charge         Charge          Charge
--------------------- --------------- --------------- ------------------------------- --------------- ------------- ----------------
<S>                      <C>              <C>             <C>            <C>              <C>           <C>              <C>
Gas Distribution      $    187,342    $     27,164    $     160,178   $    151,217    $      8,582    $    8,724    $        (142)
Electric Services          122,188             191          121,997         77,099          57,119        13,525           43,594
Gas Exploration
    and Production          58,211               -           58,211         15,772           2,218             -            2,218
Energy Services             40,946               -           40,946         (2,528)         (3,212)            -           (3,212)
Energy Investments          13,929               -           13,929          8,543          (4,186)            -           (4,186)
Other                      (98,850)         13,717         (112,567)       (26,244)        (52,036)       19,763          (71,799)
-----------------------------------------------------------------------------------------------------------------------------------
Consolidated          $    323,766    $     41,072    $     282,694   $    223,859   $       8,485   $    42,012    $     (33,527)
Special Charges                                                                                                          (162,010)
-----------------------------------------------------------------------------------------------------------------------------------
Consolidated                                                                                                        $    (195,537)
--------------------- --------------- --------------- ------------------------------- --------------- ------------- ----------------
</TABLE>

Consolidated  earnings for 2000 were $2.10 per share compared to $1.62 per share
in 1999.  Consolidated  results  for 2000  reflect  a  charge  of $41.1  million
after-tax,  or $0.31 per share,  associated with early  retirement and severance
programs that were implemented upon the successful completion of the Eastern and
ENI acquisitions.  Excluding these charges,  consolidated earnings for 2000 were
$2.41 per share. Our average common shares outstanding were approximately  three
percent  lower for the year ended  December 31, 2000  compared to the year ended
December 31, 1999 due to a stock  repurchase  program in 1999.  The lower shares
outstanding had a favorable affect on earnings per share of approximately $0.06.

Consolidated  results  for the  Transition  Period  reflect  a loss of $1.34 per
share.  During the Transition Period, we: (i) incurred a charge of $42.0 million
after-tax,  or $0.29 per share, associated with implementing an early retirement
program;  (ii) incurred  substantial  non-recurring  charges associated with the
LIPA Transaction of $107.9 million  after-tax,  or $0.74 per share,  principally
reflecting  taxes  associated with the sale of assets to KeySpan by LIPA and the
write- off of certain  regulatory  assets that were no longer  recoverable under
various LIPA  agreements;  and (iii) recorded an after-tax  non-cash  impairment
charge of $54.1  million,  or $0.37  per  share,  representing  our share of the
impairment charge recorded by our gas exploration and production subsidiary, The
Houston Exploration  Company ("Houston  Exploration") to recognize the effect of
lower wellhead  prices on its valuation of proved gas reserves.  (See Note 16 to
the Consolidated  Financial  Statements,  "Costs Related to the LIPA Transaction
and Special  Charges" for further  details of these  charges.)  Excluding  these
early  retirement and special charges,  earnings for the Transition  Period were
$8.5 million, or $0.06 per share.

The  increase in earnings for 2000 over 1999,  and for 1999 over the  Transition
Period  resulted  from solid  performance  across all of our business  segments.
Further,  as has been  previously  noted,  earnings  for the  Transition  Period
include  only  seven  months of  results  of  operations  for the KSE-  acquired
companies  and do not  reflect  heating  season  operations  (months  of January
through March) when approximately 80% of our gas related earnings are realized.

The increase in earnings from the Gas Distribution segment for 2000, compared to
last year reflects revenue  benefits from continued gas sales growth,  favorable
gas prices  compared  to oil prices for most of the year and  earnings  from our
newly acquired gas distribution  companies.  Since the date of acquisition,  the
combined gas  distribution  operations of Eastern and ENI added $22.3 million to
consolidated  earnings.  The  increase  in Gas  Distribution  earnings  in  1999
compared to the Transition Period reflects,  primarily the addition of KEDNY for
a full twelve month period and earnings  generated for an entire heating season.
Earnings  growth  in both 2000 and 1999  associated  with our  Electric  Service
segment reflects primarily the operations  associated with our investment in the
2,200 megawatt Ravenswood electric generation facility,  ("Ravenswood facility")
located in Queens,  New York. The Ravenswood  facility was acquired in June 1999
and therefore,  earnings for 2000 reflect a full year of operations,  while 1999
reflects  less than seven full months of  operations.  Earnings  from our Energy
Services  segment  in  2000  were  derived  largely  from   inter-company   fuel
procurement and energy management services provided to the Ravenswood  facility,
as  well  as  earnings  from  our  recently  acquired   companies  that  provide
energy-related services.

Consolidated  earnings for 2000 compared to 1999 were further  enhanced  through
improved  performance from our Gas Exploration and Production segment and Energy
Investments segment. Gas exploration and production  operations  benefitted from
significantly  higher  realized gas prices and increased  production  volumes in
2000.  In  addition,  on March 31, 2000 we  increased  our  ownership in Houston
Exploration  from  64% to  70%.  Results  of  operations  in  1999  reflect  gas
exploration and production operations for a full twelve months compared to seven
months for the  Transition  Period,  as well as the  benefit  from the  combined
effect of  increases  in both gas  production  volumes  and gas  prices.  Energy
Investments  reflect the  continued  development  and  integration  of companies
acquired over the past few years.

The Other segment reflects preferred stock dividends,  general expenses incurred
by our corporate and  administrative  areas that have not been  allocated to our
various  business  segments,  and  interest  income  earned  on  temporary  cash
investments.  The significant increase in the loss incurred by the Other segment
in 2000 compared to 1999 reflects the following: (i) additional contributions to
the KeySpan Foundation, a not-for-profit philanthropic foundation that makes

                                        3

<PAGE>



donations to local charitable community  organizations;  (ii) charges related to
certain rate  settlement  issues;  (iii) losses  incurred with our investment in
certain technology-related  activities; (iv) branding expenses and other charges
related  to the  integration  of the  Eastern  and ENI  companies  into  KeySpan
operations; (v) an increase in interest expense associated with higher levels of
commercial paper  outstanding;  and (vi) lower interest income on temporary cash
investments.  The Other  segment  showed a smaller loss in 1999  compared to the
Transition  Period.  Transition Period results reflected a donation to establish
the KeySpan Foundation and a charge to write-off a customer-billing  system that
was in development.

Revenues

Consolidated revenues are derived primarily from our two core operating segments
- Gas  Distribution  and Electric  Services.  In 2000,  these two core  segments
accounted for approximately 78% of consolidated  revenues. For 2000 consolidated
revenues  were $5.1  billion,  compared to $3.0 billion for 1999, an increase of
$2.1  billion or 73%.  The  increase  was due  primarily  to: (i) an increase in
revenues from the Ravenswood facility of $534.8 million; (ii) an increase in Gas
Distribution revenues of $802.7 million; and (iii) an increase of $585.3 million
from the Energy Services segment.

Revenues  from the  Ravenswood  facility  benefitted  from  the sale of  energy,
capacity and  ancillary  services to the New York  Independent  System  Operator
("NYISO")  at  competitive  market  prices.  Prior to the  start of the NYISO on
November 19 1999,  all of the energy and capacity from the  Ravenswood  facility
was  sold to  Consolidated  Edison  Company  of New  York,  Inc.  ("Consolidated
Edison") on a cost  recovery  and fixed fee basis.  Further,  revenues  for 2000
reflect a full year of operations.  Revenues from the Gas  Distribution  segment
benefitted from continued gas sales growth,  favorable gas prices as compared to
oil  prices  for most of 2000 and the  acquisition  of  Eastern's  and ENI's gas
distribution operations. Revenues from the Gas Distribution segment also include
recovery of gas costs, which have been significantly  higher in 2000 compared to
1999. The increase in revenues from the Energy  Services  segment  resulted from
recent  acquisitions  of companies  providing  various  energy-related  services
throughout the New York City  metropolitan  area, Rhode Island and Pennsylvania,
and sales growth related to our gas and electric marketing subsidiary.

The increase in consolidated revenues of $1.2 billion, or 71%, in 1999, compared
to the Transition  Period,  reflects  primarily revenues from gas heating sales.
For the months of January 1999 through  March 1999,  gas  distribution  revenues
were $718.3 million.  The Transition Period,  which reflects the period April 1,
1998 through  December 31, 1998,  does not include  revenues from heating season
operations for the months of January  through March.  Further,  revenues in 1999
reflect a full twelve  month  period for all  segments,  whereas the  Transition
Period reflects revenues for only seven months from the KSE- acquired companies.
Revenues in 1999 also include  $150.8  million of revenues  from the  Ravenswood
facility and were further  enhanced  through the acquisition of companies in the
Energy Services segment.





                                        4

<PAGE>



Operating Expenses

Consolidated  operating  expenses  were $4.4  billion in 2000,  compared to $2.5
billion  last year,  an  increase  of $1.9  billion,  or 78%.  The  increase  in
operating  expenses was primarily  the result of higher gas and  purchased  fuel
costs, and higher operations and maintenance  expenses.  Consolidated  operating
expenses  were $1.8  billion  during the  Transition  Period.  The  increase  in
operating  expenses in 1999 compared to the Transition Period of $694.7 million,
or 39%,  is due,  in part,  to the  increased  reporting  time  frame  and to an
increase of $248.9 million in operations  and  maintenance  expense  reflecting,
primarily  the addition of the  KSE-acquired  companies  for a full twelve month
period.

Purchased Gas for Resale

The increase in gas costs for 2000 compared to last year resulted from gas sales
growth  associated with our two New York gas  distribution  subsidiaries and our
gas and electric marketing subsidiary,  significantly higher gas prices, and the
addition of the Eastern and ENI gas  distribution  operations which added $180.6
million to gas costs in 2000. The increase in gas costs for 1999 compared to the
Transition  Period is due to  changes  in gas  quantities  and  prices,  and the
differences  in the reporting  periods  presented.  Fluctuations  in utility gas
costs have  little or no impact on  operating  results as the  current  gas rate
structure of each of our gas  distribution  utilities  includes a gas adjustment
clause,  pursuant to which variations  between actual gas costs incurred and gas
cost  recoveries  are deferred and refunded to or collected  from customers in a
subsequent period.  Fluctuations in gas costs,  however,  can affect earnings of
our  gas  and  electric  marketing   subsidiary.   To  mitigate  this  potential
volatility,  this subsidiary employs derivative financial instruments to hedge a
portion of the risk associated with future gas cost prices.  (See Note 10 to the
Consolidated  Financial Statements "Hedging,  Derivative Financial  Instruments,
and Fair Values".)

Fuel and Purchased Power

Fuel and  purchased  power  expense  in 2000 was  $460.9  million  and  reflects
expenses  associated with the operation of the Ravenswood  facility,  as well as
expenses  associated with our gas and electric  marketing  subsidiary  which has
been  making  retail  electric  sales  to  residential,  small  commercial,  and
industrial  customers  since January 2000. Fuel expense for the operation of the
Ravenswood facility was $315.1 million in 2000. Fuel and purchased power expense
for 1999 was $17.3 million and reflects  expenses  associated with the operation
of the  Ravenswood  facility  only. In 1999,  the prior owner of the  Ravenswood
facility,  Consolidated Edison, owned and supplied the fuel necessary to operate
the  Ravenswood  facility  from June 19,  1999  until  the start of the  NYISO's
operations on November 19, 1999.  Further,  during this time,  all of the energy
generated by the Ravenswood facility was supplied to Consolidated Edison.

Electric  fuel  expense  was $91.8  million  during the  Transition  Period.  In
accordance  with the energy  management  agreement  ("EMA")  between KeySpan and
LIPA,  LIPA is  responsible  for paying  directly the costs of fuel,  as well as
purchased  power to satisfy the energy needs of LIPA's  customers.  As a result,
since May 29, 1998, we no longer incur any electric fuel expense for Long Island
generation.

                                        5

<PAGE>



Operations and Maintenance

Operations and maintenance  expense  increased by $669.5 million or 61%, in 2000
compared  to last year,  primarily  as a result of: (i) recent  acquisitions  of
companies  providing various energy- related services which increased  operating
expenses in 2000 by 32%; (ii) the  operations of the  Ravenswood  facility for a
full twelve months which increased  operating expenses in 2000 by 13%; and (iii)
the  recent  acquisition  of  Eastern  and ENI  which  added  $89.9  million  to
operations and maintenance expense in 2000. Further, we incurred a $65.2 million
charge in 2000 for early retirement and severance programs.

Operations and maintenance  expense  increased by $248.9 million or 30%, in 1999
compared  to the  Transition  Period.  The  increase  was due  primarily  to the
addition of the  KSE-acquired  companies  for a full twelve month period and the
increased reporting time frame generally. Operations and maintenance expense for
the  KSE-acquired  companies was $483.6  million for 1999 and $284.1 million for
the  Transition  Period.  Further,  the increase in  comparative  operations and
maintenance  expense  in  1999  was  due,  in  part,  to the  operations  of the
Ravenswood  facility,  which added  $61.3  million to  expense.  Operations  and
maintenance  expense for the Transition  Period  included $63.8 million of costs
associated  with  the  write-off  of a  customer  billing  system  that  was  in
development and a charge of $64.6 million  associated  with an early  retirement
program.

Other Operating Expenses

Depreciation,  depletion and amortization expense reflects primarily gas utility
property  and  electric  generation  property  additions,  as well as  depletion
expense associated with our gas exploration and production activities.  Property
additions and gas production activities have increased in 2000 compared to 1999,
resulting in higher depreciation, depletion and amortization expense.

Depreciation,   depletion  and  amortization   expense  also  reflects  goodwill
amortization  which  increased  in 2000  compared to 1999  primarily  due to the
amortization of goodwill  associated  with the  acquisitions of Eastern and ENI.
The goodwill associated with these acquisitions amounted to $1.5 billion and the
amortization  for the period  November  8, 2000  through  December  31, 2000 was
approximately $6.5 million. (See Note 1 to the Consolidated Financial Statements
"Summary of Significant Accounting Policies" for a description of goodwill.)

The  decrease  in  depreciation,  depletion  and  amortization  expense  in 1999
compared to the  Transition  Period is due  primarily  to the fact that  Houston
Exploration  recorded an  impairment  charge of $130 million in December 1998 to
reduce the value of its proved gas reserves in accordance with the asset ceiling
test limitations of the Securities and Exchange Commission ("SEC") applicable to
gas  exploration and  development  operations  accounted for under the full cost
method. Excluding this impairment charge, depreciation expense increased in 1999
due to property additions, the addition of the KSE-acquired companies for a full
twelve month period and the increased reporting period generally.



                                        6

<PAGE>



Operating taxes  principally  include state and local taxes on utility  revenues
and  property.  The  applicable  property  base  and tax  rates  generally  have
increased in all  periods.  Further,  the  increase in  operating  taxes in 2000
compared  to 1999 is also  due to a full  twelve  months  of  operations  of the
Ravenswood facility and the addition of Eastern and ENI. Operating taxes for the
Ravenswood  facility in 2000 were $46.6  million  compared  to $19.6  million in
1999. Eastern and ENI added $8.6 million to operating taxes in 2000.

The  increase in operating  taxes in 1999,  compared to the  Transition  Period,
reflects the  addition of the KSE-  acquired  companies  for a full twelve month
period, and operating taxes associated with the Ravenswood  facility.  Operating
taxes associated with the KSE-acquired companies were $140.8 million in 1999 and
$69.8 million during the Transition Period.

Other Income and Deductions

Other income  includes  equity income from  subsidiaries  comprising  the Energy
Investments  segment,  primarily our investments in Canada.  In addition,  other
income  includes  interest  income  from  temporary  cash  investments,  certain
non-operating  expenses and the effect on net income from the minority  interest
associated primarily with Houston Exploration. In October 2000, we increased our
investment in Gulf Midstream Services Partnership ("Gulf Midstream"), located in
Alberta Canada,  from 50% to 100% and renamed these operations "KeySpan Canada."
As a result, since October 2000 the results of operations of KeySpan Canada have
been  reported  on a  consolidated  basis and are no longer  reported  in equity
income.

The  decrease in other  income in 2000  compared to 1999  reflects  primarily an
increase in non-  operating  charges and lower interest  income.  During 2000 we
made a $10 million donation to the KeySpan Foundation and recorded an impairment
charge of $15.5 million on our equity  investment in certain  technology-related
activities.  Interest  income has been  decreasing  as we have utilized our cash
during the past two years to make acquisitions,  repurchase shares of our common
stock, and retire maturing debt.

Other income and  deductions in 1999  reflects  twelve months of results for our
Canadian  investments  compared to seven  months of results  for the  Transition
Period.  Further,  our 50% interest in Gulf  Midstream  was acquired in December
1998 and, therefore, there are no equity earnings associated with Gulf Midstream
for the Transition  Period.  We recognized  equity earnings of $12.9 million for
1999 from our Canadian investments,  including $5.8 million from Gulf Midstream.
Interest  income  decreased in 1999,  compared to the Transition  Period,  as we
utilized our cash to make  acquisitions,  repurchase shares of our common stock,
and retire maturing debt. Other income and deductions for the Transition  Period
reflects  non-recurring  charges  associated with the LIPA Transaction of $107.9
million  after-tax  and a $20  million  charge for the  funding  of the  KeySpan
Foundation.  (See  Note  16 to the  Consolidated  Financial  Statements,  "Costs
Related to the LIPA Transaction and Special Charges.")






                                        7

<PAGE>



Interest Expense

Interest  expense was $203.4  million,  or 52% higher in 2000,  compared to last
year reflecting  higher levels of debt  outstanding,  primarily  related to: (i)
$1.65 billion of long-term debt and $308.6 million of commercial paper issued to
finance the  acquisitions  of Eastern and ENI;  (ii) $400 million of medium term
notes  issued  in  February  2000;  (iii)  debt  associated  with  our  Canadian
investments;  as well as (iv) higher  commercial paper borrowings to satisfy our
seasonal  working capital needs.  Interest  expense  relating to the acquisition
financing of Eastern and ENI amounted to  approximately  $17.5  million in 2000.
(See Note 7 to the Consolidated Financial Statements "Long-Term Debt.")

The  decrease in interest  expense in 1999  compared  to the  Transition  Period
primarily reflects the then reduced level of outstanding debt resulting from the
LIPA  Transaction.  Upon  consummation  of the LIPA  Transaction,  LIPA  assumed
substantially all of the outstanding debt of LILCO.  KeySpan, in return,  issued
promissory  notes to LIPA for its  continuing  obligation  to pay  principal and
interest on certain series of bonds that were assumed by LIPA.  Outstanding debt
at December 31, 1999 was $1.7  billion,  compared to $4.5  billion  (LILCO only)
prior to the LIPA  Transaction.  In  addition,  interest  expense  in 1999  also
reflects the repayment of $397 million of promissory notes due LIPA that matured
in June 1999. The reduction in interest expense in 1999 from the lower levels of
debt  outstanding  was  offset,  in  part,  by the  interest  expense  from  the
KSE-acquired companies for the full twelve months.

Income Taxes

Income tax expense generally reflects the higher level of pre-tax income in 2000
compared to last year.  Further,  during the last quarter of 2000, the basis for
computing  certain local income taxes was changed which also  contributed to the
increase in income tax expense in 2000.

Income tax expense for 1999  reflects an  adjustment to deferred tax expense and
current tax expense for the  utilization  of  previously  deferred net operating
loss  carryforwards  recorded in 1998. In 1998,  we recorded,  as a deferred tax
asset,  a benefit of $71.1  million for net  operating  loss  carryforwards.  We
estimated  that  $57.4  million  of the  benefits  from the net  operating  loss
carryforwards  from 1998 would be realized in our consolidated  1999 federal and
state income tax returns and,  accordingly,  we applied the net  operating  loss
benefits in our 1999 federal and state tax  provisions.  Pre-tax  income and the
related deferred income tax expense for the Transition Period were significantly
affected by charges related to the LIPA Transaction, the write-off of a customer
billing  system,  charges  related  to the  early  retirement  program,  and the
impairment  charge  associated with the write-down of proved gas reserves.  (See
Note 3 to the Consolidated Financial Statements, "Income Tax.")








                                        8

<PAGE>



Consolidated Outlook for 2001

Results of operations for 2000 reflect strong results from our core  investments
- gas distribution, electric services and energy services. Our marketing efforts
have added  approximately  21,000 new gas heating  customers in our New York and
Long Island  service  territories  in 2000, as well as  contributing  to our gas
sales growth of approximately 5%, after normalizing for weather variations.  Our
June 1999  acquisition of the Ravenswood  facility  provided us with significant
earnings  enhancement.  Further,  our energy services operations posted positive
earnings  results  in  2000  due  to the  successful  integration  of  companies
purchased  during the past two years.  These operations are expected to form the
basis for  additional  enhancements  to  consolidated  earnings in future years.
Moreover,  our non-core  assets,  specifically  our gas and oil  exploration and
production operations, posted impressive results for 2000.

For 2001, we anticipate that consolidated  earnings will grow  approximately 10%
over the level we  achieved in 2000,  and we  forecast  earnings in the range of
$2.60 to $2.65 per share.  We believe this growth will come  primarily  from our
energy  services  operations  as  we  continue  the  successful  integration  of
companies  acquired during the past few years.  We also  anticipate  significant
earnings  growth  from our gas and oil  exploration  and  production  activities
resulting from the anticipated high price for natural gas during 2001, augmented
by our current  hedging  strategies.  Further,  we have  completed  our resource
allocation  process for 2001 and are encouraged that we will achieve the synergy
savings projected to result from the Eastern and ENI acquisitions.

The Financial  Accounting Standards Board ("FASB") recently issued a revision to
its Exposure Draft ("ED") on "Business  Combinations and Intangible  Assets". In
the new ED, the FASB concluded that the  amortization of goodwill will no longer
be required.  Instead, companies will need to perform yearly impairment tests on
the recorded  amount of goodwill and determine  whether an impairment  charge is
necessary.  We believe  the FASB will  finalize  its  deliberations  on goodwill
amortization  in the third or fourth  quarter of 2001, but are unable to predict
the ultimate outcome of its deliberations. If we are required to discontinue the
amortization of goodwill we may realize higher earnings in 2001, compared to our
current  earnings  projections,  although such  enhancement to earnings will not
affect cash flow.

As a result of the  acquisition  of Eastern  and ENI,  we are now subject to the
jurisdiction of the SEC under the Public Utility Holding Company Act of 1935, as
amended  ("PUHCA").  The rules and  regulations  under PUHCA generally limit the
operations of a registered holding company to a single integrated public utility
system,  and  non-utility   businesses  that  are  reasonably   incidental,   or
economically  necessary or  appropriate  to the system's  utility  business.  In
addition,  as part of the regulatory  provisions of PUHCA,  the SEC can regulate
certain  transactions  among  affiliates  within a holding  company  system.  In
accordance with the regulations of PUHCA, we have established  service companies
that provide: (i) traditional  corporate and administrative  services;  (ii) gas
and electric transmission and distribution systems planning,  marketing, and gas
supply planning and procurement; and (iii) engineering and surveying services to
subsidiaries. Revised methodologies approved by the SEC will be used to allocate
service  company costs to affiliates  and may result in more or less costs being
charged to the affiliates  than in previous  years.  However,  it is anticipated
that the consolidated results

                                        9

<PAGE>



will not be impacted  by the  allocations.  (See  Regulation  and Rate  Matters,
"Securities and Exchange Commission  Regulation" for additional details on PUHCA
regulations.)

Finally, we adopted Statement of Financial  Accounting Standards ("SFAS") No.133
"Accounting  for Derivative  Instruments  and Hedging  Activities" on January 1,
2001.  Currently all of our  derivative  instruments  expire prior to the end of
2001 and  therefore  we do not expect SFAS No. 133 to have a material  effect on
our net income for the year ended December 31, 2001.  However,  SFAS No. 133 may
have a significant effect on other comprehensive  income because of fluctuations
in the market  value of the  derivatives  we employ.  Further,  depending on the
quarterly measurement of hedging effectiveness,  SFAS No.133 may have a material
effect on our reported quarterly  earnings,  (See Note 10, "Hedging,  Derivative
Financial Instruments, and Fair Values" for additional information.)



                                       10

<PAGE>



Segment Review of Operations
----------------------------

The segment  review that follows  reflects the  operations of our newly acquired
companies, Eastern and ENI, for the period November 8, 2000 through December 31,
2000 and excludes after-tax charges of $41.1 million recorded in 2000 associated
with our early retirement and severance programs. Also, as previously mentioned,
due to the  change  in the  structure  of our  business  as a result of the LIPA
Transaction  and the  requirements  of  purchase  accounting  applicable  to the
KeySpan  Acquisition,  results of operations for the  Transition  Period are not
comparable  to the  results  of  operations  for 2000 and 1999.  Therefore,  for
comparative  purposes,  we have  combined the results of  operations,  excluding
non-recurring and special charges,  of KSE and LILCO for the entire twelve month
period ended  December  31,  1998.  This  combined  presentation  is intended to
reflect our results as if the KeySpan  Acquisition  occurred on January 1, 1998.
This "combined company basis" format will also be used to explain  variations in
operating  results,  for each business segment,  between the twelve months ended
December 31, 1999 and 1998.

Consolidated   income  (loss)  available  for  common  stock,   excluding  early
retirement  and  severance  charges  recorded in 2000 and early  retirement  and
special  charges  incurred  in 1998,  by  reporting  segment is set forth in the
following table for the periods indicated:

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

                                                 Year Ended                Year Ended               "Combined Company"
                                                December 31,              December 31,              Twelve Months Ended
                                                    2000                      1999                   December 31, 1998
------------------------------------------ ----------------------  -------------------------- -----------------------------------
<S>                                                <C>                       <C>                          <C>
Income (Loss ) Available for
Common Stock:
Gas Distribution                           $        187,342        $           151,217       $              133,685
Electric Services                                   122,188                     77,099                      120,568*
Gas Exploration and Production                       58,211                     15,772                        8,995
Energy Services                                      40,946                     (2,528)                      (8,623)
Energy Investments                                   13,929                      8,543                       (6,098)
Other                                               (98,850)                   (26,244)                     (53,221)
---------------------------------------------------------------------------------------------------------------------------------
                                           $        323,766        $           223,859       $              195,306
------------------------------------------ ----------------------  -------------------------- -----------------------------------
</TABLE>
   *  Reflects results of operations  under the LIPA service  agreements for the
      period May 29, 1998 through  December 31, 1998 and electric  operations of
      the former LILCO for the period January 1, 1998 through May 28, 1998.






                                       11

<PAGE>



Gas Distribution

With the exception of a small  portion of Queens  County,  our gas  distribution
subsidiaries are the only providers of gas distribution services in the New York
City  counties of Kings,  Richmond  and Queens and the Long  Island  counties of
Nassau and Suffolk. KEDNY provides gas distribution services to customers in the
New York City boroughs of Brooklyn,  Queens and Staten  Island,  and KeySpan Gas
East Corporation  d/b/a 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.  Our newly  acquired gas
distribution  subsidiaries,  Boston Gas Company, Colonial Gas Company, Essex Gas
Company, and EnergyNorth Natural Gas, each doing business under the name KeySpan
Energy  Delivery New England  ("KEDNE"),  provide gas  distribution  services to
customers in Massachusetts and New Hampshire.

The table below  highlights  certain  significant  financial  data and operating
statistics for the Gas Distribution segment for the periods indicated.
<TABLE>

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

                                                         Year Ended                  Year Ended                 "Combined Company"
                                                        December 31,                December 31,               Twelve Months Ended
                                                            2000                        1999                    December 31, 1998
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>                          <C>                               <C>
Revenues                                          $       2,555,785       $           1,753,132       $                 1,766,949
Cost of gas                                               1,303,514                     702,044                           702,669
Revenue taxes                                               117,811                     108,488                           109,194
-----------------------------------------------------------------------------------------------------------------------------------
Net Revenues                                              1,134,460                     942,600                           955,086
-----------------------------------------------------------------------------------------------------------------------------------
Operating expenses
  Operations and maintenance                                458,082                     415,888                           464,296
  Depreciation and amortization                             143,335                     102,997                            91,438
  Operating taxes                                           131,854                     115,305                           106,891
-----------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                    733,271                     634,190                           662,625
-----------------------------------------------------------------------------------------------------------------------------------
Operating Income                                  $         401,189       $             308,410       $                   292,461
-----------------------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock                         $         187,342       $             151,217       $                   133,685
-----------------------------------------------------------------------------------------------------------------------------------
Firm gas sales (MDTH)                                       216,000                     172,019                           165,331
Firm transportation (MDTH)                                   40,655                      21,249                            13,974
Transportation -
   Electric Generation (MDTH)                                49,854                      82,503                            40,614
Other sales (MDTH)                                           91,406                      54,661                            65,482
Degree days                                                   4,902                       4,296                             3,940
(Colder) Warmer than normal                                  (2.1%)                       10.0%                             17.5%
Heating customers (000)                                       1,260                         677                               665
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
      An MDTH is 10,000 therms (British  Thermal Units) and reflects the heating
      content of  approximately  one million cubic feet of gas. A therm reflects
      the heating  content of  approximately  100 cubic feet of gas. One billion
      cubic feet (BCF) of gas equals approximately 1,000 MDTH.


                                       12

<PAGE>



Net Revenues

Net gas revenues  (revenues less the cost of gas and  associated  revenue taxes)
increased by $191.9 million or 20% in 2000 compared to 1999, due to the addition
of the gas distribution  operations of Eastern and ENI which contributed  $126.6
million to net  revenues,  continued  gas sales growth and  favorable gas prices
compared to oil prices during most of the year.

Net gas revenues  decreased in 1999 compared to 1998 by $12.5 million,  or 1.3%,
due primarily to rate reductions associated with the KeySpan Acquisition.  KEDNY
reduced  rates to its  core  customers  by  $23.9  million  on an  annual  basis
effective  May 29, 1998 and KEDLI  reduced its rates to core  customers by $12.2
million  annually  effective  February 5, 1998 and by an additional $6.3 million
annually  effective  May 29, 1998.  For the year ended  December 31, 1999,  rate
reductions affected revenues by approximately $19.2 million compared to 1998.

Firm net gas revenues grew approximately  $154.2 million in 2000, over 1999. The
gas distribution  operations of Eastern and ENI added $126.6 million to net firm
revenues,  while our New York  based gas  distribution  operations  added  $27.6
million to firm net revenues  through the addition of new gas  customers and oil
to gas  conversions,  primarily in the Long Island  market,  as well as from the
benefits of colder  weather.  Long Island has a low natural gas saturation  rate
for space  heating  use and  significant  gas  sales  growth  opportunities  are
believed to be  available.  We estimate that on Long Island less than 40% of the
residential and multi- family markets,  and  approximately 55% of the commercial
market  currently  use  natural  gas for  space  heating.  Further,  we  believe
significant gas sales growth  opportunities  exist in the New England market due
to the relatively low  penetration of customers using gas for space heating use.
We estimate  that in our New England  service  territories  less than 50% of the
residential and multi-family  markets,  and  approximately 30% of the commercial
market currently use natural gas for space heating.  In both our Long Island and
New England service areas, we will continue to seek growth through the expansion
of our gas distribution system, as well as through the conversion of residential
homes  from   oil-to-gas   for  space  heating   purposes  and  the  pursuit  of
opportunities to grow multi-family,  industrial and commercial markets. Firm net
gas  revenues  grew  approximately  $14  million  in 1999  over  1998 due to the
addition of new gas  customers  and oil to gas  conversions,  primarily  on Long
Island, as well as from the benefits of colder weather.

In the large volume heating markets and other interruptible  (non-firm) markets,
which include large  apartment  houses,  government  buildings and schools,  gas
service  is  provided  under  rates  that  are set to  compete  with  prices  of
alternative  fuel,  including No. 2 and No. 6 grade heating oil. While the price
of both heating grade fuel oil and natural gas increased  significantly in 2000,
gas  generally  sold at a slight  discount  to heating  oil during the year.  We
increased sales in these markets by $21.9 million in 2000 compared to last year,
through  aggressive  unit pricing and the addition of two large  commercial  and
industrial  customers.  The majority of interruptible  profits earned by Eastern
and ENI are refunded to firm  customers.  During 1999,  gas generally  sold at a
premium to heating oil. Nevertheless,  we increased sales in this market in 1999
compared to 1998, by approximately $6 million,  through  aggressive unit pricing
and the addition of new customers.



                                       13

<PAGE>



Net  revenues in 2000 were also  favorably  affected  by recovery of  previously
deferred  property  taxes.  Contributing  to the  reduction in  comparative  net
revenues  in  1999  compared  to  1998  was a  decrease  in  certain  regulatory
incentives, and since April 1998 net revenues no longer reflect revenues derived
by KEDNY from certain  appliance and repair  services which were "spun-off" to a
subsidiary in the Energy Services segment.

KEDNY and KEDLI each  operate  under a utility  tariff  that  contains a weather
normalization adjustment that largely offsets shortfalls or excesses of firm net
revenues during a heating season due to variations from normal weather.  The gas
distribution  operations  of our New England  based  subsidiaries  do not have a
weather normalization adjustment.  As a result,  fluctuations in weather between
years  may  have a  significant  effect  on  results  of  operations  for  these
subsidiaries.

Sales, Transportation and Other Quantities

Firm gas sales  quantities  increased by 20% in 2000 compared to 1999 reflecting
firm sales from our newly acquired New England gas distribution operations,  the
addition of new gas customers as discussed  above, and the benefits derived from
colder weather.  Weather normalized sales quantities  increased by approximately
5% in 2000 compared to 1999 in our New York and Long Island service territories,
while the addition of the New England gas distribution operations increased firm
sales by 12%. The 4% increase in gas sales  quantities for 1999 compared to 1998
reflects  an  increase  of 2.4% in  weather  normalized  firm  sales  quantities
resulting from customer additions and oil-to-gas  conversions and colder weather
in 1999.

Firm gas transportation  quantities increased in all periods, as we continue our
natural gas  deregulation  initiatives.  At  December  31,  2000,  approximately
126,500  residential,  commercial and  industrial  customers in our New York and
Long  Island  service  territories  purchased  their gas supply from third party
suppliers  compared  to  approximately  46,000  customers  in  1999  and  32,900
customers  in 1998.  The New England gas  distribution  subsidiaries  also offer
unbundled  services to all commercial and industrial  customers.  As of December
31,  2000,  these  subsidiaries  had  approximately  4,000  firm  transportation
customers.   Unbundled  service  to  Massachusetts   residential  customers  was
effective  November 1, 2000.  Our net  revenues  are  currently  not affected by
customers opting to purchase their gas supply from other sources, since delivery
rates charged to transportation customers are generally the same as the delivery
component of the total rates charged to full sales service customers.

Transportation   quantities   related  to   electric   generation   reflect  the
transportation  of gas to our  electric  generating  facilities  located on Long
Island. Net revenues from these services are not material.

Other sales quantities include on-system  interruptible  quantities,  off-system
sales quantities  (sales made to customers  outside of our service  territories)
and  related  transportation.  Effective  April  1,  2000,  we  entered  into an
agreement  with Coral  Resources,  L.P.  ("Coral"),  a  subsidiary  of Shell Oil
Company. Coral assists in the origination,  structuring, valuation and execution
of  energy-related  transactions.  Under our New York Public Service  Commission
("NYPSC")  approved  rate plans,  net  revenues  realized  from  off-system  gas
transactions are shared between

                                       14

<PAGE>



gas  customers  and  KEDNY and  KEDLI.  A portion  of the net  revenues  on such
transactions  accruing to KEDNY and KEDLI are then shared with Coral.  KEDNY and
KEDLI also share in net revenues arising from certain transactions  initiated by
Coral.  Prior to this  agreement  with Coral,  KEDNY had an agreement with Enron
Capital and Trade Resources Corp., a subsidiary of Enron Corp., which expired on
March 31, 2000. Pursuant to that agreement,  Enron provided gas supply and asset
management  services to KEDNY for a fee, and obtained the right to earn revenues
based  upon  its  management  of  KEDNY's  gas  supply   requirements,   storage
arrangements  and  interstate  pipeline  capacity  rights.  As a result  of this
agreement, KEDNY did not report any off-system sales quantities in 1999.

Effective  November 1, 1999, the  Massachusetts  based gas subsidiaries  entered
into a three-year  portfolio  management contract with El Paso Energy Marketing,
Inc.  El Paso  provides  all of the city gate supply  requirements  to the three
Massachusetts  companies at market prices and manages  certain of the companies'
upstream  capacity,   underground   storage  and  term  supply  contracts.   The
Massachusetts  Department of Telecommunications  and Energy ("DTE") approved the
contract  in  October  1999.  The  annual  fee  paid by El Paso  to  manage  the
companies' portfolio is, for the most part, returned to firm customers.

Operating Expenses

Operating expenses increased by $99.1 million,  or 16%, in 2000 compared to last
year due  primarily  to the  addition of  Eastern's  and ENI's gas  distribution
operations.  Eastern  and ENI  collectively  added  $69.8  million to  operating
expenses in 2000. This amount includes operations and maintenance costs of $42.0
million,  depreciation  and  amortization  charges of $21.9  million and general
taxes of $5.9 million.  Included in the depreciation and amortization charge, is
an expense of  approximately  $5.9  million  primarily  representing  two months
amortization of goodwill associated with the acquisition of Eastern and ENI that
was  assigned  to  gas  distribution  operations.   The  remaining  increase  in
depreciation and amortization expense reflects continued property additions, and
the  amortization of certain costs  previously  deferred and now being recovered
through revenue recovery  mechanisms.  Further,  operating taxes,  which include
state and local taxes on property have increased as the applicable property base
and tax rates generally have increased.

Operating expenses decreased in 1999 compared to 1998 by $28.4 million, or 4.3%.
During 1999, we realized  significant  reductions in operations and  maintenance
expense reflecting,  primarily the benefits derived from cost reduction measures
and operating  efficiencies employed in prior years. Such measures included, but
were not  limited  to,  the  early  retirement  program  completed  in 1998.  In
addition,  KEDNY's "spin-off" of non-safety related appliance repair services to
an Energy  Services  subsidiary  in April 1998  contributed  to the reduction in
operations  and  maintenance  expense  for  this  segment.   KEDLI  discontinued
providing  non-safety related appliance repair services on July 1, 1999, further
reducing operating expenses for this segment.

The increase in depreciation and  amortization  expense in 1999 compared to 1998
reflects  continued  property  additions  and  the  amortization  of  previously
deferred merger related  expenses.  As provided for in the settlement  agreement
approved by the NYPSC,  by which the NYPSC  authorized the KeySpan  Acquisition,
KEDNY and KEDLI deferred certain merger

                                       15

<PAGE>



related costs at the time of the merger.  These costs are being amortized over a
ten year period. (See Gas Distribution - Rate Matters for further details on the
Stipulation Agreement.)

Earnings

In addition to the matters  discussed  earlier,  earnings  available  for common
stock also reflect interest expense and income tax provisions.  Interest expense
for 2000 was $21.3 million higher  compared to last year due to $16.6 million of
interest expense associated with the gas distribution  operations of Eastern and
ENI and the  issuance of $400  million of medium term notes in February  2000 by
KEDLI.  Included in interest  expense is $9.4 million  associated  with the debt
incurred  to acquire  Eastern and ENI.  Further,  we incurred an increase in our
income tax provision  due to a change in our basis for  computing  certain local
income taxes.

The increase in earnings in 1999  compared to 1998  reflects  primarily  the net
result of the items  mentioned  above.  In  addition,  earnings  were  favorably
affected  by  carrying  charges  on  certain  regulatory   deferrals  previously
mentioned as well as lower interest expense.

Future Developments

We believe there remains significant growth opportunities in our Long Island and
New England gas distribution  service areas.  The Northeast region  represents a
significant portion of the country's  population and energy consumption.  As our
gas distribution  operations  evolve within the new deregulated gas environment,
gas sales growth will remain a critical core  strategy.  Customer  additions are
and will remain critical to our earnings enhancement in the future. We intend to
continue  our gas  growth  initiatives  on Long  Island  and in the New  England
region.  The beneficial effect of these initiatives,  however,  may not be fully
realized in the short-term since we will make incremental investments in our gas
distribution  network  and expand our  promotional  campaigns  to  optimize  the
long-term  growth  opportunities  in our  territories.  Our current forecast for
capital   expenditures  in  2001  is  $404  million  and  reflects   anticipated
expenditures  for our  gas  expansion  initiatives  on  Long  Island  and in New
England.

To take advantage of the anticipated gas sales growth  opportunities  in the New
York City metropolitan  area, we recently announced that we have formed Islander
East Pipeline, L.L.C., a limited liability company in which a KeySpan subsidiary
and a subsidiary of Duke Energy  Corporation each own a 50% equity interest.  It
is  anticipated  that  Islander East will design,  construct,  own and operate a
natural gas pipeline  facility  consisting of  approximately 40 miles of 24-inch
and  30-inch  diameter  pipeline   extending  from  Algonquin  Gas  Transmission
Company's  facilities in  Connecticut,  across the Long Island Sound and connect
with KEDLI's  facilities  on Long Island.  This  pipeline,  which is expected to
begin  operating in the last quarter of 2003, will initially  transport  250,000
dth of gas capacity daily to the Long Island and New York City energy markets.


                                       16

<PAGE>



Electric Services

The Electric  Services segment  primarily  consists of subsidiaries that own and
operate oil and gas fired electric  generating plants in Queens and Long Island,
through  long-term   contracts,   and  manage  the  electric   transmission  and
distribution ("T&D") system, the fuel and electric purchases, and the off-system
electric  sales for LIPA.  Prior to the LIPA  Transaction,  LILCO provided fully
integrated electric  distribution services to over one million customers on Long
Island.

Selected  financial data for the Electric  Services  segment is set forth in the
table below for the periods indicated.
<TABLE>
<CAPTION>
(In Thousands of Dollars)
---------------------------------------------------------------------------------------------------------------------------------

                                                    Year Ended                 Year Ended               "Combined Company"
                                                    December 31,              December 31,              Twelve Months Ended
                                                       2000                       1999                   December 31, 1998
-------------------------------------------  -------------------------  ------------------------  ------------------------
<S>                                                 <C>                        <C>                      <C>
Revenues
  LIPA service agreements                    $          758,251         $         708,002       $           408,305
  Ravenswood facility                                   685,605                   150,836                         -
  Electric distribution                                       -                         -                   885,693
  Other                                                     855                     2,744                         -
-------------------------------------------  -------------------------  ------------------------  ------------------------
Total Revenues                                        1,444,711                   861,582                 1,293,998
 Purchased fuel                                         315,139                    17,252                   257,786
-------------------------------------------  -------------------------  ------------------------  ------------------------
Net Revenues                                          1,129,572                   844,330                 1,036,212
-------------------------------------------  -------------------------  ------------------------  ------------------------
Operating expenses
  Operations and maintenance                            682,196                   527,729                   461,903
  Depreciation                                           49,278                    44,334                    79,404
  Regulatory amortizations                                    -                         -                   (79,874)
  Operating taxes                                       158,886                   132,327                   218,418
-------------------------------------------  -------------------------  ------------------------  ------------------------
Total Operating Expenses                                890,360                   704,390                   679,851
-------------------------------------------  -------------------------  ------------------------  ------------------------
Operating Income                             $          239,212         $         139,940       $           356,361
-------------------------------------------  -------------------------  ------------------------  ------------------------
Earnings for Common Stock                    $          122,188         $          77,099       $           120,568
-------------------------------------------  -------------------------  ------------------------  ------------------------
Electric sales (MWH)*                                 4,952,613                 2,995,970                         -
Cooling degree days*                                      1,165                     1,416                         -
Capacity (MW)*                                            2,200                     2,168                         -
-------------------------------------------  -------------------------  ------------------------  ------------------------
</TABLE>
           *Reflects the operations of the Ravenswood facility only.


                                       17

<PAGE>



Revenues

Net revenues increased by $285.2 million,  or 34%, in 2000 compared to last year
due primarily to a full year of operations of the Ravenswood facility.  Revenues
from the Ravenswood  facility  benefitted from the sale of energy,  capacity and
ancillary services to the NYISO at competitive market prices, and from effective
hedging  strategies.  Prior to the start of  operations of the NYISO on November
19, 1999, all of the energy and capacity from the  Ravenswood  facility was sold
to Consolidated  Edison on a cost recovery and fixed fee basis.  Further,  there
were no sales of ancillary services in 1999.

Due to the volatility in the  market-clearing  price for electricity and certain
ancillary services in the NYISO energy markets, the sales prices for both energy
sales and the sale of certain ancillary services to the NYISO are now subject to
price  caps and  other  price  mitigation  measures.  Certain  price  mitigation
measures are currently being finalized, and the final resolution of these issues
and their effect on our financial  position and results of operations can not be
determined  at this  point in time.  (See Note 8 to the  Consolidated  Financial
Statements,  "New York State Independent  System Operator Matters" for a further
discussion of these matters.)

Purchased  fuel  expense  in 2000  and 1999  represents  costs  to  operate  the
Ravenswood  facility.  In 1999,  Consolidated Edison owned and supplied the fuel
necessary to operate the facility  from June 19, 1999 until the NYISO  commenced
operations. As a result, we did not incur any fuel expense prior to November 19,
1999.

Revenues from our service agreements with LIPA were $50.2 million higher in 2000
compared to last year.  The  increase is largely due to the  construction  of an
underground  transmission  line to reinforce the electric system capacity on the
southfork of Long Island.  The project was performed  under a fixed fee contract
with LIPA, as part of the management  services agreement.  Further,  revenues in
2000 include  $16.5 million of  off-system  sales from our Long Island  electric
generation  units.  Under the terms of the energy management  agreement,  we are
entitled  to one-  third of the profit  from any  off-system  electricity  sales
arranged by us on LIPA's  behalf.  In addition,  in 2000 we earned $15.4 million
associated  with  non-cost  performance  incentives  provided  for  under  these
agreements,  compared to $15.8 million  earned last year.  (For a description of
the LIPA service agreements, see "LIPA Agreements.")

Revenues related to the LIPA service  contracts  increased in 1999,  compared to
the Transition  Period, due primarily to the fact that 1999 reflects a full year
of operations under these contracts.  In addition, as previously  mentioned,  we
earned $15.8 million associated with non-cost  performance  incentives  provided
for under  these  agreements.  Revenues  were  further  enhanced  in 1999 by the
operations of the Ravenswood  facility.  However, net revenues in 1999 decreased
by $191.9  million,  or 19%,  compared to 1998. As a result of the change in the
nature of our  electric  operations  due to the LIPA  Transaction,  our electric
capital investment has been significantly reduced and accordingly,  our revenues
and margins under the LIPA contracts reflect that reduction.

Purchased  fuel expense  decreased by $240.5  million in 1999  compared to 1998,
reflecting  primarily the  discontinuance  of fuel and  purchased  power expense
associated with the generating

                                       18

<PAGE>



facilities  located on Long Island.  In  accordance  with the energy  management
agreement, LIPA is responsible for paying directly the costs of fuel, as well as
purchased power to satisfy its customers. As a result, since May 29, 1998, we no
longer incur any electric  fuel expense for Long Island  generation or purchased
power expense.

Operating Expenses

Operating  expenses in 2000 increased by $186.0 million or 26% compared to 1999.
The  increase in  operating  expenses in 2000  reflects  the  operations  of the
Ravenswood  facility for a full year.  Operating  expenses  associated  with the
Ravenswood  facility  increased  by $143.7  million  in 2000  compared  to 1999.
Included in operating expenses for the Ravenswood  facility are charges of $63.9
million for fuel management  services provided by one of our subsidiaries within
the Energy Services segment. There were no comparable charges in 1999. Operating
expenses  incurred under LIPA service  agreements  increased by $42.3 million in
2000  compared to last year due  primarily to costs  incurred to install the new
electric transmission line discussed above.

Operating  expenses increased slightly in 1999 compared to 1998. The increase in
operations and maintenance  expense was offset, in large measure,  by a decrease
in  depreciation  expense  and  operating  taxes.  Since  the LIPA  Transaction,
operations  and  maintenance  expense  includes  the costs  associated  with the
management  of the T&D  assets  acquired  by LIPA.  All T&D  related  costs  are
expensed  when  incurred and  recovered  from LIPA through  monthly  billings in
accordance  with the terms of the management  services  agreement.  Prior to the
LIPA  Transaction,  all T&D  related  construction  costs were  capitalized  and
charged to  depreciation  expense over the estimated  useful life of the related
asset.  Depreciation  expense and operating  taxes  decreased in 1999 due to the
sale of  significant  property  related  assets  to LIPA as a result of the LIPA
Transaction.

Earnings

In addition to the matters discussed above,  earnings available for common stock
also reflect  interest  expense,  as well as city,  state and federal income tax
provisions.  During 2000, the basis for computing certain local income taxes was
changed and, as a result, we recorded higher taxes in 2000 compared to 1999.

Earnings  in 1999  compared  to 1998 were  favorably  affected  by a decrease of
$135.3 million in interest  expense  reflecting the then  significantly  reduced
level of outstanding debt resulting from the LIPA Transaction. Further, prior to
the  KeySpan  Acquisition,   approximately  $18.2  million  of  preferred  stock
dividends  were allocated to electric  operations.  Partially  offsetting  these
benefits was the elimination of carrying charges on certain electric  regulatory
assets resulting from electric ratemaking mechanisms that have been discontinued
due to the LIPA Transaction.

Future Developments

During  2000,  we filed  an  application  with  the  NYPSC to build a new 250 MW
cogeneration  facility at the Ravenswood facility site. We recently received the
preliminary  permits  and are moving  forward  with the  licensing  effort.  The
facility, which will generate electricity and

                                       19

<PAGE>



steam, is expected to commence service in 2003. Further, we continue to evaluate
the electric needs on Long Island and may, if economic  circumstances and energy
needs warrant,  proceed with strategies to add additional  electric  capacity on
Long Island.  As discussed,  in greater detail under the heading  Regulation and
Rate Matters  "Securities and Exchange  Commission  Regulation,"  our ability to
invest in  electric  generating  facilities  is subject to certain  restrictions
imposed by the SEC.

Under a "Generation  Purchase Rights Agreement" entered into as part of the LIPA
Transaction,  LIPA has the right to purchase,  at fair market value,  all of our
Long Island based generating  assets during the twelve month period beginning on
May 28,  2001.  During the fourth  quarter  of 2000,  LIPA began an initial  due
diligence  review of the feasibility of purchasing these assets and has recently
expressed an intent to solicit proposals from interested  parties to operate the
generating  facilities  should they purchase them. At this point in time, we can
not predict whether LIPA will exercise its right to purchase the assets, nor can
we estimate the effect on our  financial  condition or results of  operations if
LIPA were to exercise such right.

Gas Exploration and Production

The Gas Exploration and Production segment is engaged in gas and oil exploration
and production,  and the development and acquisition of domestic natural gas and
oil  properties.  This  segment  consists of our 70% equity  interest in Houston
Exploration, as well as KeySpan Exploration and Production LLC, our wholly owned
subsidiary  engaged  in a joint  venture  with  Houston  Exploration.  Effective
December 31, 2000, KeySpan and Houston Exploration  mutually agreed that we will
no longer  participate  in Houston  Exploration's  future  offshore  exploration
prospects.  We will,  however,  continue to maintain our working interest in all
wells drilled under the joint venture agreement.  We also agreed to continue the
development  of our working  interests in prospects  drilled  under the drilling
program,  and for the year  2001,  we have  agreed to commit  approximately  $17
million for the  development of prospects  successfully  drilled during 1999 and
2000. On March 31, 2000, under a pre-existing credit arrangement,  approximately
$80 million in debt owed by Houston Exploration to us was converted into Houston
Exploration  common equity.  Upon such  conversion,  our common equity ownership
interest in Houston Exploration increased from 64% to approximately 70%.















                                       20

<PAGE>



Selected  financial data and operating  statistics for the Gas  Exploration  and
Production  segment  are set  forth  in the  following  table  for  the  periods
indicated.
<TABLE>
<CAPTION>
                                                                                                    (In Thousands of Dollars)
----------------------------------------------------------------------------------------------------------------------------
                                                                                                      "Combined Company"
                                                             Year Ended           Year Ended            Twelve Months
                                                            December 31,         December 31,               Ended
                                                                2000                 1999             December 31, 1998
----------------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>                <C>                       <C>
Revenues                                              $         274,209    $       150,581              $    127,124
Depletion and amortization                                       95,364             74,051                    79,839
Other operating expenses                                         44,435             28,000                    27,250
----------------------------------------------------   -----------------   -----------------            -----------------
Operating Income                                      $         134,410    $        48,530              $     20,035
----------------------------------------------------    -----------------  -----------------            -----------------
Earnings for Common Stock                             $          58,211    $        15,772                   $8,995*
----------------------------------------------------    -----------------  -----------------            -----------------
Natural gas and oil production (Mmcf)                            80,415             71,227                    62,829
Natural gas (per Mcf) realized                        $            3.38    $          2.10              $       2.02
Natural gas (per Mcf) unhedged                        $            3.97    $          2.14              $       1.96
Proved reserves at year-end (BCFe)                                  593                553                       480
----------------------------------------------------    -----------------  -----------------            -----------------
</TABLE>
           Operating  income above  represents  100% of our gas  exploration and
           production subsidiaries' results for the periods indicated. Earnings,
           however, are adjusted to reflect minority interest and,  accordingly,
           include 70% of Houston  Exploration's results since April 1, 2000 and
           64% of  Houston  Exploration's  results  for all prior  periods.  Gas
           reserves and production are stated in BCFe and Mmcfe,  which includes
           equivalent oil reserves.

           *Excludes an after-tax charge of $54.1 million representing our share
           of an impairment charge to reduce the value of proved gas reserves.

Operating Income

Operating income increased by $85.9 million,  or 177%, in 2000 compared to 1999.
The increase in operating  income  reflects a significant  increase in revenues,
partially offset by increases in operating  expenses.  Revenues  benefitted from
the combined  effect of a 13% increase in production  volumes and a 61% increase
in average  realized gas prices (average  wellhead price received for production
plus hedging gains and losses).  The average  realized gas price in 2000 was 85%
of the average unhedged  natural gas price,  resulting in revenues for 2000 that
were  $46.3  million  lower than the  revenues  Houston  Exploration  would have
achieved had derivative  instruments  not been in place during 2000. The average
realized  price in 1999  was 98% of the  average  unhedged  natural  gas  price,
resulting in revenues  for 1999 that were $2.6  million  lower than the revenues
that Houston Exploration would have achieved had derivative instruments not been
in  place  during  1999.  The  increase  in  operating   expenses  reflects  the
significant increase in production volumes.

Operating income increased by $28.5 million,  or 142%, in 1999 compared to 1998,
due to  higher  revenues  and,  to a lesser  extent,  a  decrease  in  operating
expenses.  Revenues in 1999 reflect the benefits  derived from a 13% increase in
production volumes,  combined with a 4% increase in average realized gas prices.
The  comparative  decrease  in  operating  expenses in 1999 was largely due to a
lower  depletion rate,  resulting  primarily from the ceiling test write down in
1998.

                                       21

<PAGE>




At December 31, 2000 our gas  exploration  and production  subsidiaries  had 593
BCFe of net proved  reserves  of natural  gas, of which  approximately  77% were
classified as proved developed.

Future Developments

Houston  Exploration  has  entered  into  options  that  are  designed  to hedge
approximately 70% of its anticipated 2001 production.  These options,  which are
referred to as "cost free  collars,"  have an average  floor price between $3.63
per Mcf and $4.00 per Mcf and an average  ceiling price of between $5.30 per Mcf
and  $6.37  per Mcf.  (See  Note 10 to the  Consolidated  Financial  Statements,
"Hedging,  Derivative Financial Instruments, and Fair Values" for an explanation
of these derivative  instruments.) In November,  Houston Exploration announced a
major  new  offshore  discovery.   Based  on  initial  test  drilling,   Houston
Exploration  estimates that this site, located offshore Louisiana and Texas, has
potential reserves of twelve million barrels of oil. Additional  undrilled fault
blocks offer  unrisked  exploration  potential of an additional  twelve  million
barrels of oil.  Houston  Exploration is the operator of this site and has a 55%
working interest.  Through our joint venture with Houston Exploration we own the
remaining 45%  interest.  Production  from this site is not expected  until late
fourth  quarter 2001 or first  quarter of 2002.  We estimate  that  consolidated
capital expenditures to develop this site will be approximately $50 million.

We consider our gas and oil exploration and production activities to be non-core
assets.  We have  stated in the past  that we may sell all or a  portion  of our
non-core  assets  if we  receive  what we  consider  to be fair  value for these
assets.  We anticipate  that if we were to sell a portion or all of our non-core
assets,  we would use the  proceeds  from the sale to  retire a  portion  of our
outstanding debt.

Energy Services

The Energy Services segment primarily  includes  companies that provide services
through  four  lines of  business  to clients  located  within the New York City
metropolitan area, Rhode Island, Pennsylvania,  Massachusetts and New Hampshire.
The lines of business  are: home energy  services;  business  solutions;  energy
commodity procurement; and fiber optic services.

During 2000, the Energy  Services  segment  acquired four  additional  companies
located in the New York City  metropolitan  area. The newly  acquired  companies
specialize in engineering-  consulting,  plumbing and mechanical contracting and
heating, ventilation and air conditioning contracting. Combined, these companies
have over 1,300 employees and revenues of approximately $260 million.





                                       22

<PAGE>



The  table  below  highlights  selected  financial  information  for the  Energy
Services segment.
<TABLE>
<CAPTION>
                                                                                             (In Thousands of Dollars)
-------------------------------------------------------------------------------------------------------------------------
                                                                                                      "Combined Company"
                                                 Year Ended                Year Ended                    Twelve Months
                                                December 31,              December 31,                       Ended
                                                    2000                      1999                     December 31, 1998
-------------------------------------------------------------------------------------------------------------------------
<S>                                               <C>                       <C>                                  <C>
Unaffiliated revenues                     $        771,861         $          186,529           $                  88,822
Intersegment revenues                               63,912                          -                                   -
Cost of goods sold                                 652,138                    152,460                              82,496
----------------------------------------  ----------------            ---------------                  ------------------
Gross Profit Margin                                183,635                     34,069                               6,326
Depreciation and amortization                       10,511                      3,548                               1,509
Other operating expenses                            95,319                     35,164                              19,115
----------------------------------------  ----------------            ---------------                  ------------------
Operating Income (Loss)                   $         77,805         $           (4,643)          $                 (14,298)
----------------------------------------  ----------------            ---------------                  ------------------
Earnings (Loss) for
     Common Stock                         $         40,946         $           (2,528)          $                  (8,623)
----------------------------------------  ----------------            ---------------                  ------------------
</TABLE>

The  increase  in earnings of the Energy  Services  segment in 2000  compared to
1999,  reflects  primarily  fuel-management  services provided to the Ravenswood
facility,  which for 2000, resulted in inter-company profits of $33.7 million. A
subsidiary within this segment,  KeySpan Energy Supply,  provides the Ravenswood
facility with energy procurement  advisory services and acts as an energy broker
for the sale of energy,  capacity,  and ancillary services.  For these services,
KeySpan  Energy  Supply  receives a management  fee and shares in the  operating
profit generated by the Ravenswood facility on the sale of energy, capacity, and
ancillary services. There was no energy procurement and fuel-management advisory
services agreement between KeySpan Energy Supply and the Ravenswood  facility in
1999.

This segment also realized  significantly  greater gross profit margins in 2000,
compared  to last year,  for each of its other  lines of  business.  These gross
margin  enhancements  resulted from recent  acquisitions of companies  providing
energy-related  services and through customer additions related to energy sales.
These  benefits to gross profit  margins were  partially  offset by increases in
general and administrative  expenses associated primarily with the operations of
the newly acquired companies.

The  decrease  in the loss in 1999  compared  to 1998 was due to an  increase in
revenues of 100%,  offset, in part, by an increase in operating expenses of 85%.
The  increase  in  comparative  revenues  reflects  the  benefits  derived  from
companies  acquired  during  1999 and  1998  and the  growth  in the  number  of
customers purchasing energy from our gas and electric marketing subsidiary.  The
comparative  increase in operating expenses was due primarily to the integration
of  operations  of  companies  acquired  during  1999 and  1998,  and  increased
purchased gas costs of our gas and electric  marketing  subsidiary  necessary to
serve a larger  customer  base.  The  formation and  commencement  of operations
associated with our appliance  repair services in April 1998 also contributed to
the comparative increase in operating expenses in 1999.


                                       23

<PAGE>



Energy Investments

Earnings  for this segment are derived from our 20% interest in the Iroquois Gas
Transmission  System LP; our ownership of KeySpan Canada; our ownership interest
in certain oil producing properties in Alberta,  Canada; and our 50% interest in
the Premier Transco  Pipeline and 24.5% interest in Phoenix Natural Gas, both in
Northern  Ireland.  Premier is a natural gas  transmission  pipeline  connecting
Scotland and Northern  Ireland in the United  Kingdom,  and Phoenix is a natural
gas  distribution  company  serving Belfast in Northern  Ireland.  In the fourth
quarter of 2000,  we sold our interest in certain oil  producing  properties  in
Alberta,  Canada and recognized an after-tax gain of approximately  $1.3 million
from the sale.  Further, in the fourth quarter of 2000, we became the sole owner
of Gulf  Midstream by acquiring the remaining 50% interest in this company.  For
financial  reporting  purposes,  the operations of Gulf Midstream  d/b/a KeySpan
Canada have now been fully consolidated.

Earnings from this segment  increased by $5.4 million,  or 63%, in 2000 compared
to last year reflecting earnings growth from our Canadian  investments.  Results
of operations  from Canadian gas and oil  operations  were enhanced  through the
acquisition,  in the fourth  quarter of 1999,  of the Paddle River Gas Plant and
certain oil producing  properties in Alberta,  Canada, more efficient operations
of KeySpan  Canada and the  additional  ownership  interest in that company.  In
addition,  Iroquois realized higher transportation sales quantities and revenues
from its  interruptible  customers  during  this period  compared  with the same
period last year.  Earnings from our investments in Northern Ireland in 2000 are
essentially  the same as  earnings  for last  year.  For much of the  year,  the
subsidiaries  in this  segment  were  primarily  accounted  for under the equity
method since our ownership interests were 50% or less. Accordingly,  income from
these  investments is reflected,  primarily in other income and  (deductions) in
the Consolidated Statement of Income.

Earnings  from  this  segment  increased  by $14.6  million  in 1999  reflecting
primarily  earnings from our  investment in Gulf  Midstream,  formed in December
1998,  and more  favorable  results from  investments  in Northern  Ireland.  In
addition,  in 1998 results of  operations  from this segment  reflect  after-tax
costs of $7.8 million to settle certain  contracts  associated with the sale, in
1997,  of  certain   cogeneration   investments   and  related  fuel  management
operations.

Future Developments

We consider this segment to be a non-core investment.  As mentioned  previously,
we may sell all or a portion of our non-core  assets  within the next few years.
At this point in time,  we can not predict  when we may sell any of our non-core
assets, or the effect such sale may have on our financial  position,  results of
operations, or cash flows.



                                       24

<PAGE>



Other

The Other segment reflects preferred stock dividends,  general expenses incurred
by our corporate and  administrative  areas that have not been  allocated to our
various  business  segments,  and  interest  income  earned  on  temporary  cash
investments. Further, this segment includes results of operations related to our
in-land marine transportation subsidiary, Midland Enterprises, that was acquired
as part  of the  Eastern  acquisition.  The  significant  increase  in the  loss
incurred by the Other segment in 2000  compared to 1999 reflects the  following:
(i) an after-tax  charge of $6.5 million for an additional  contribution  to the
KeySpan  Foundation;  (ii) an  after-tax  charge of $6.0 related to certain rate
settlement issues; (iii) a loss of $15.1 million, after tax, associated with our
investment in certain technology-related  activities; (iv) branding expenses and
other costs related to the integration of the Eastern and ENI companies into our
operations  of $16  million;  and (v) an increase  in interest  expense of $23.8
million associated with higher levels of commercial paper outstanding.  Further,
we realized $9.0 million less in interest income,  after- tax, on temporary cash
investments  as we utilized  cash to finance  certain  acquisitions,  repurchase
shares of our common stock,  and retire maturing debt during the past two years.
Pursuant to an order of the SEC issued under PUHCA by which the SEC approved the
Eastern and ENI acquisitions,  we are required to divest our interest in Midland
Enterprises  by no later than  November 8, 2003 because its  operations  are not
functionally related to our core utility operations.

The Other segment incurred a loss of $26.2 million in 1999 compared to a loss of
$52.0  million in 1998.  In 1999 we  recognized  $15  million  less in  interest
income,  after-tax, on temporary cash investments due to the utilization of cash
to finance  certain  acquisitions,  repurchase  shares of our common stock,  and
retire maturing debt. In 1998 the Other segment  recorded an after-tax charge of
$41.5 million to write-off a customer  billing  system that was in  development.
Further, we made a $20 million donation,  $13 million after-tax,  to the KeySpan
Foundation.

Liquidity

Cash  flow  from  operations  for  2000  reflects  stable  growth  from  our gas
distribution  operations,  as well as positive  contributions  from our electric
operations.  The decrease in cash flow from  operations in 2000 compared to last
year however, reflects working capital requirements primarily as a result of the
rising  price of  natural  gas in the  later  part of 2000.  As a result  of the
seasonal nature of our gas distribution  operations,  we incur  significant cash
expenditures  during the summer  and early fall to fill our  storage  facilities
with natural gas that is used by our customers during the winter heating season.
We recover these costs in subsequent  periods as the gas is removed from storage
and sold to our customers primarily for space heating purposes. Significant cash
flows are  generated  during the first and  second  quarters  of the  subsequent
fiscal year as we receive  payments from  customers for such use. Cash flow from
operations  also  reflects a decrease  in  interest  income,  and an increase in
interest payments due to increased levels of outstanding debt.  Further, in 1999
cash flow from operations  reflects the cash  utilization of a $57.4 million net
operating  loss  carryforward  on income tax  payments for 1999,  as  previously
discussed.

                                       25

<PAGE>



The increase in cash flow from  operations  in 1999  compared to the  Transition
Period  reflects the  significant  positive  cash flows  realized  from revenues
generated during the heating season,  continued strong results from core utility
operations,  cash  generated  from the  Ravenswood  facility,  and the  benefits
derived from the  integration  of  KSE-acquired  companies  for an entire twelve
month period.  Results from gas-heating  season  operations are not reflected in
the Transition  Period, as previously  explained.  Further,  as indicated above,
cash flow from  operations in 1999 reflects the  utilization  of a $57.4 million
net  operating  loss  carryforward  on income tax payments  for 1999.  Moreover,
during the Transition  Period,  $250 million was funded into Voluntary  Employee
Beneficiary Trusts to fund certain employee postretirement welfare benefits and,
as a result,  cash flow from operations for the Transition  Period was adversely
affected.

At December  31,  2000,  we had cash and  temporary  cash  investments  of $94.5
million. In addition, we have two revolving credit agreements, with a commercial
bank syndicate totaling $1.4 billion. These agreements expire in September 2001,
and our current intention is to renew these agreements.  These credit facilities
are used to support our $1.4 billion  commercial paper program.  At December 31,
2000,  $1.3 billion of commercial  paper was  outstanding at a weighted  average
annualized  interest rate of 7.01%. We had available  borrowing of $99.7 million
at December 31, 2000.  Commercial  paper was issued  during 2000 to: (i) finance
approximately  $309 million of the  approximately  $2.0 billion  purchase  price
associated  with the  acquisitions of Eastern and ENI; (ii) redeem our preferred
stock  7.95%  Series AA for $363  million;  and (iii)  support  ongoing  working
capital needs.

Houston  Exploration has an unsecured available line of credit with a commercial
bank that provides for a maximum commitment of $250 million,  subject to certain
conditions.  During 2000,  Houston  Exploration  borrowed $32 million  under its
credit  facility and repaid $68 million;  at December 31, 2000,  $145.0  million
remained outstanding at a weighted average annualized interest rate of 7.90%. At
December 31, 2000, Houston  Exploration had available  borrowing of $65 million.
Also, a subsidiary  included in the Energy Investments segment has two revolving
loan agreements with financial  institutions in Canada.  Borrowings  under these
agreements  during 2000 were $83.6  million,  including  the  financing  for the
purchase of the remaining 50% interest in Gulf Midstream.  At December 31, 2000,
$171 million was outstanding at a weighted average  annualized  interest rate of
6.43%. The Energy Investments  segment currently has available  borrowing of $46
million. (See Note 7 to the Consolidated Financial Statements,  "Long-Term Debt"
for further information on these agreements.)

We  satisfy  our  seasonal  working  capital   requirements   primarily  through
internally generated funds and the issuance of commercial paper. In addition, we
utilize Treasury Stock to satisfy the requirements of our common stock plans. We
believe that these sources of funds are sufficient to meet our seasonal  working
capital needs.



                                       26

<PAGE>



Capital Expenditures and Financing

Construction Expenditures

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

                                                       (In Thousands of Dollars)
--------------------------------------------------------------------------------
                                              Actual               Estimated
                                            Year Ended            Year Ended
                                         December 31, 2000     December 31, 2001
--------------------------------------------------------------------------------
Gas Distribution                         $     274,941  $           404,000
Electric Services                               69,921               59,000
Gas Exploration and Production                 243,799              245,000
Energy  Services                                17,362               18,000
Energy Investments and Other                    27,012               66,000
                                         -------------  -------------------
                                         $     633,035  $           792,000
---------------------------------------  -------------  -------------------

Construction  expenditures related to the Gas Distribution segment are primarily
for the renewal and  replacement  of mains and services and for the expansion of
the gas  distribution  system on Long  Island and in New  England.  Construction
expenditures  for  2000  include  costs  associated  with  the gas  distribution
operations of Eastern and ENI for two months.  Construction expenditures for the
Electric  Services  segment  reflect  primarily  costs to maintain  our electric
generating facilities.  Construction expenditures related to the Gas Exploration
and Production  segment  reflect,  in part,  costs related to the development of
properties  acquired in Southern Louisiana and in the Gulf of Mexico in 1999 and
costs  related  to the  continued  development  of other  properties  previously
acquired.  Expenditures also include development costs associated with our joint
venture with Houston  Exploration.  Energy  Investments  and Other  construction
expenditures reflect, primarily costs related to Canadian affiliates.

The amount of future  construction  expenditures is reviewed on an ongoing basis
and can be affected by timing, scope and changes in investment opportunities.

Equity Investments

During 2000, we made a number of significant equity  investments.  As previously
mentioned,  we  acquired  Eastern  and  ENI in  November,  and we  acquired  the
remaining  50% in Gulf  Midstream  during the last quarter of 2000. In addition,
during 2000, the Energy  Services  segment  acquired four  additional  companies
located in the New York City  metropolitan  area. The newly  acquired  companies
specialize in engineering-consulting,  plumbing and mechanical contracting,  and
heating, ventilation and air conditioning contracting. Combined, these companies
have over 1,300 employees and revenues of approximately $260 million.



                                       27

<PAGE>



Financing

In connection  with our  acquisition of Eastern and ENI, we issued $1.65 billion
of long-term  debt. The debt was issued in three  different  maturities  ranging
from five to thirty years in the following denominations: (i) $700 million 7.25%
Notes due 2005;  (ii) $700 million 7.625% Notes due 2010; and (iii) $250 million
8.00%  Notes due 2030.  The  interest  on the notes is payable on a  semi-annual
basis on May 15 and November 15 of each year,  beginning May 15, 2001. The total
purchase price for the Eastern and ENI  acquisitions  was $1.959 billion and, as
previously  indicated,  we issued approximately $309 million of commercial paper
for additional financing. (See Note 12 to the Consolidated Financial Statements,
"Eastern/EnergyNorth Acquisitions" for further details on the transactions.)

In  anticipation  of the issuance of long-term  debt  securities  to finance the
Eastern and ENI  acquisitions,  we entered into forward starting swap agreements
during 2000 to hedge a portion of the risk that the cost of the future  issuance
of  fixed-rate  debt may be adversely  affected by increases in interest  rates.
Under the forward starting swaps, we agreed to pay or receive an amount equal to
the  difference  between the net present  value of the cash flows for a notional
amount of  indebtedness  based on the existing yield of a hedging  instrument at
the date of the  agreement  and at the  date the  agreement  is  settled.  These
derivative  instruments  were  settled  at the  closing of the  Eastern  and ENI
transactions.

KEDLI had an effective shelf registration statement on file with the SEC for the
issuance of up to $600 million of medium term notes. On February 1, 2000,  KEDLI
issued $400 million  7.875% Notes due  February 1, 2010.  The net proceeds  from
this  issuance  were used to  reimburse  our  treasury  for costs in paying $397
million of promissory  notes to LIPA that matured in June 1999. In January 2001,
KEDLI issued an additional $125 million of medium term notes at 6.9% due January
15, 2008. The medium term notes issued are fully and unconditionally  guaranteed
by us.  We  intend  to use the  proceeds  from  this  financing  to fund our gas
expansion initiatives on Long Island. (See Note 7 to the Consolidated  Financial
Statements, "Long-Term Debt" for more information regarding outstanding debt.)

In June 2000, we redeemed, at maturity,  preferred stock 7.95% Series AA through
the utilization of internally generated funds and the proceeds from the issuance
of commercial  paper.  Our obligation of $370.2  million  included the mandatory
redemption price of $25 per share totaling $363.0 million and a dividend payable
totaling $7.2  million.  We anticipate  issuing  preferred  stock during 2001 to
replace this series that matured.

In 1998, our Board of Directors authorized the repurchase of up to 10 percent of
our then outstanding  stock, or approximately 15 million common shares. A second
authorization  permitted us to use up to an additional  $500 million of cash for
the  purchase of common  shares.  In 1999,  we  completed  this  program and now
utilize Treasury Stock to satisfy the requirements of our common stock plans. At
December 31, 2000, we had 22.5 million shares,  or $650.7  million,  of Treasury
Stock remaining.


                                       28

<PAGE>

During 2001,  we will  continue to evaluate our capital  structure  and debt and
equity  levels.Further,  we will  manage our balance  sheet to  maintain  strong
ratings at each of our rated  entities.  We believe that our sources of funding,
i.e. anticipated preferred stock issuances, reissuing common stock from Treasury
Stock and the  availability of commercial paper borrowings will be sufficient to
meet our anticipated cash needs. Further, as mentioned  previously,  we may sell
all or a portion of our non-core assets. At December 31, 2000 our ratio of debt,
including  commercial  paper, to total  capitalization  was  approximately  66%.
However, if we divest of certain non-core assets, we believe that we can achieve
a debt to  capitalization  ratio of  approximately  55% within the next  several
years.  As a registered  holding  company,  we are subject to certain  financing
restrictions.  See the  discussion  under the heading  "Securities  and Exchange
Commission Regulation" for additional information.

In the fourth quarter of 2000,  Moody's Investor Service confirmed the rating on
KeySpan's  long- term debt at A3 and  confirmed the rating on KEDNY's and Boston
Gas Company's long-term debt at A2. The rating on Midland Enterprises' long-term
debt was  confirmed at A3 and the ratings on KEDLI's and Colonial Gas  Company's
long-term  debt were  confirmed  at A2.  Standard and Poor's  rating  agency has
confirmed the long-term debt rating on KeySpan,  KeySpan Generation,  Boston Gas
Company and Colonial Gas Company at A.  KEDNY's and KEDLI's  long-term  debt was
confirmed at A+.

Dividends

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

Pursuant  to the  NYPSC's  orders  dated  February  5, 1998 and  April 14,  1998
approving  the  KeySpan  Acquisition,  the  ability  of KEDNY  and  KEDLI to pay
dividends to the parent  company is  conditioned  upon  maintenance of a utility
capital  structure with debt not exceeding 55% and 58%,  respectively,  of total
utility  capitalization.  In  addition,  the  level  of  dividends  paid by both
utilities may not be increased  from current  levels if a 40 basis point penalty
is  incurred  under the  customer  service  performance  program.  At the end of
KEDNY's and  KEDLI's  rate years  (September  30, 2000 and  November  30,  2000,
respectively),  the ratio of debt to total  utility  capitalization  was 44% and
46%,  respectively.  Our corporate and financial activities and those of each of
our  subsidiaries  (including  their  ability to pay  dividends  to us) are also
subject to regulation by the SEC. For additional information, see the discussion
under the heading "Securities and Exchange Commission Regulation" .

Regulation and Rate Matters

Gas Distribution
By  orders  dated  February  5, 1998 and April  14,  1998 the NYPSC  approved  a
settlement agreement among Brooklyn Union, LILCO, the Staff of the Department of
Public  Service  and six other  parties  that in  effect  approved  the  KeySpan
Acquisition  and  established  gas rates for both  KEDNY  and  KEDLI.  Under the
agreement, $1 billion of efficiency savings, excluding gas

                                       29

<PAGE>



costs, attributable to operating synergies that are expected to be realized over
the 10 year period following the combination, were allocated to customers net of
transaction costs.

Under the settlement  agreement,  effective May 29, 1998,  KEDNY's base rates to
core customers were reduced by $23.9 million annually. In addition, KEDNY is now
subject to an earnings sharing  provision  pursuant to which it will be required
to credit core customers with 60% of any utility earnings up to 100 basis points
above certain  threshold  return on equity levels over the term of the rate plan
(other than any earnings  associated  with discrete  incentives)  and 50% of any
utility earnings in excess of 100 basis points above such threshold levels.  The
threshold  levels are 13.50% for the rate years  ended  September  30,  2000 and
2001, and 13.25% for the rate year 2002.  KEDNY exceeded the threshold return on
equity by 123 basis points for the rate year ended September 30, 2000.

The  settlement  agreement  also  required  KEDLI to  reduce  base  rates to its
customers  by  $12.2  million  annually  effective  February  5,  1998 and by an
additional $6.3 million annually  effective May 29, 1998. KEDLI is subject to an
earnings  sharing  provision  pursuant to which it is required to credit to firm
customers  60% of any utility  earnings in any rate year up to 100 basis  points
above a return on equity of 11.10% and 50% of any utility  earnings in excess of
a return on equity of  12.10%.  KEDLI did not earn  above its  threshold  return
level in its rate year ended  November 30, 2000.  On November 30, 2000,  KEDLI's
rate agreement with the NYPSC expired. Under the terms of the agreement, current
gas distribution rates will remain in effect for 2001 unless either KEDLI or the
NYPSC initiate a rate proceeding. We do not intend to initiate such a proceeding
and at this time we have no reason to  believe  that the NYPSC  will  initiate a
proceeding. Therefore, we expect current gas distribution rates for our New York
and Long Island based gas  distribution  utilities  to remain in effect  through
2001.

Boston Gas Company's gas rates for local distribution  service are governed by a
five-year  performance-based rate plan approved by the DTE in 1996 (the "Plan").
Under  the  Plan,  Boston  Gas  Company's  rates  for  local   distribution  are
recalculated  annually to reflect  inflation  for the  previous  12 months,  and
reduced by a  productivity  factor of 1%. The  productivity  factor has been the
subject of a remand  proceeding  at the DTE as  discussed  below.  The plan also
calls for  penalties  if Boston  Gas  Company  fails to meet  specified  service
quality measures, with a maximum potential expense of $1 million, which has also
been a  subject  in the  DTE's  remand  proceeding.  There is a  margin  sharing
mechanism,  whereby  25% of  earnings  in excess of a 15%  return on equity  are
passed back to  customers.  Similarly,  ratepayers  absorb 25% of any  shortfall
below a 7% return on equity.

With respect to the appeal by Boston Gas Company of the Plan, the  Massachusetts
Supreme   Judicial  Court  issued  an  order  vacating:   (i)  the  "accumulated
inefficiencies"  component  of the  productivity  factor,  thereby  reducing the
productivity  factor from 1.50% to .50%;  and (ii) the  expansion of the service
quality  penalty  beyond $1 million,  and remanded  these matters to the DTE for
further  proceedings,  which actions were requested by the DTE in its motion for
discharge of report and remand.  On January 16, 2001, the DTE issued an order in
the  remand  proceeding.  The order  imposes a 0.5%  accumulated  inefficiencies
factor,  thereby increasing the productivity factor from 0.5% to 1% and sets the
maximum service quality adjustment at $1

                                       30

<PAGE>



million. The order requires the accumulated inefficiencies factor be implemented
retroactively  as of November 1, 1999.  On January 30, 2001,  Boston Gas Company
filed a Petition for Appeal and Motion for a Stay with the Massachusetts Supreme
Judicial Court, and on February 16, 2001, the court granted the stay pending the
appeal. We are unable to predict the ultimate outcome of this proceeding.

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

The SEC's order issued on May 8, 2000, in  connection  with our  acquisition  of
Eastern and ENI,  provides us with, among other things,  authorization to do the
following through December 31, 2003 (the "Authorization Period"): (a) subject to
an aggregate amount of $5.1 billion, (i) maintain existing financing agreements,
(ii) issue and sell up to $1.5 billion of  additional  securities  in compliance
with certain defined  parameters,  (iii) issue  additional  guarantees and other
forms of credit  support in an  aggregate  amount of $2.0 billion at any time in
addition to any such  securities,  guarantees and credit support  outstanding or
existing as of November 8, 2000, and (iv) amend, review,  extend,  supplement or
replace any of the foregoing; (b) issue shares of common stock or reissue shares
of common stock held in treasury under  dividend  reinvestment  and  stock-based
management incentive and employee benefit plans; (c) maintain existing and enter
into additional hedging transactions with respect to outstanding indebtedness in
order to manage and minimize  interest rate costs;  (d) invest up to 250% of our
consolidated  retained  earnings  in exempt  wholesale  generators  and  foreign
utility companies;  and (e) pay dividends out of capital and unearned surplus as
well as paid-in-capital with respect to certain subsidiaries, subject to certain
limitations.

In addition,  we have committed that during the Authorization Period, our common
equity will be at least 30% of our consolidated  capitalization  and each of our
utility  subsidiaries'  common  equity  will be at  least  30% of such  entity's
capitalization.










                                       31

<PAGE>



Electric Services - Revenue Mechanisms

LIPA Agreements

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

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

Power Supply Agreement ("PSA")
A  KeySpan  subsidiary  sells to LIPA all of the  capacity  and,  to the  extent
requested,  energy  from  our  existing  Long  Island  based  oil and  gas-fired
generating plants. Sales of capacity and energy are made under rates approved by
the Federal Energy Regulatory Commission ("FERC").  The rates may be modified in
the future in accordance with the terms of the PSA for (i) agreed upon labor and
expense  indices  applied to the base year,  (ii) a return of and on net capital
additions required for the generating facilities,  and (iii) reasonably incurred
expenses that are outside our control. 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  amount  of  megawatt  hours  dispatched.  LIPA has no
obligation  to  purchase  energy  from us and is able to  purchase  energy  on a
least-cost   basis  from  all  available   sources   consistent   with  existing
interconnection  limitations of the T&D system. We must, therefore,  operate our
generating facilities in a manner such that we can remain competitive with other
producers of energy.  To date, we have  dispatched to LIPA and LIPA has accepted
the level of energy generated at the agreed to price per megawatt hour. However,
no assurances  can be given as to the level and price of energy to be dispatched
to LIPA in the future. The PSA provides  incentives and penalties that can total
$4  million  annually  for  the  maintenance  of the  output  capability  of the
generating facilities. The PSA runs for a term of fifteen years.



                                       32

<PAGE>



As discussed previously, beginning on May 28, 2001, LIPA will have the right for
a one-year period to acquire all of our Long Island based  generating  assets at
the fair  market  value at the time of the  exercise  of the right,  which value
would be determined by independent appraisers.

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

Ravenswood Facility

At the time of our purchase of the Ravenswood facility, KeySpan and Consolidated
Edison  entered  into  transition  energy  and  capacity  contracts.  The energy
contract  provided  Consolidated  Edison with 100% of the energy produced by the
Ravenswood facility and covered a period of time from the date of closing,  June
18,  1999,  through  November  18,  1999.  With the  start-up of the NYISO,  the
electricity  market in New York City began a transition to a competitive  market
for capacity,  energy and ancillary services.  Starting on November 18, 1999, we
began selling the energy  produced by the Ravenswood  facility  through  bidding
into the NYISO  energy  markets on a day ahead or real time basis.  We also have
the option to enter into bilateral  transactions to sell all or a portion of the
energy  produced by the Ravenswood  facility to Load Serving  Entities  ("LSE"),
i.e. entities that sell to end-users or to brokers and marketers.  At this point
in time,  we have sold  energy  exclusively  through  the  NYISO.  The  capacity
contract, which provided Consolidated Edison with 100% of the available capacity
of the  Ravenswood  facility  expired on April 30,  2000.  Since that date,  the
available  capacity of the Ravenswood  facility has been bid into on the auction
process  conducted  by the NYISO.  We also have the option to sell the  capacity
through bilateral contracts.  It is anticipated that in 2001,  approximately 50%
of earnings from the  Ravenswood  facility  will be derived from capacity  sales
through either the auction  process  associated with the NYISO or contracts with
LSEs.

Environmental Matters

KeySpan  is  subject to  various  federal,  state and local laws and  regulatory
programs  related  to  the   environment.   Ongoing   environmental   compliance
activities,  which  have  not  been  material,  are  charged  to  operation  and
maintenance activities.  We estimate that the remaining cost of our manufactured
gas plant ("MGP")  related  environmental  cleanup  activities,  including costs
associated  with the Ravenswood  facility and costs  associated with Eastern and
ENI MGP sites,  will be  approximately  $137.5  million  and we have  recorded a
related  liability  for such  amount.  Eastern has  recorded an  additional  $20
million liability representing the estimated environmental

                                       33

<PAGE>



cleanup costs related to a former coal tar processing  facility.  Further, as of
December  31,  2000,  we have  expended  a total  of  $29.1  million,  including
expenditures  made by  Eastern  and ENI  since  acquisition.  (See Note 9 to the
Consolidated Financial Statements, "Contractual Obligations and Contingencies.")

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are subject to various risk exposures and  uncertainties  associated with our
operations.  The most significant  contingency involves the evolution of the gas
distribution  industry toward a more  competitive  and deregulated  environment.
Most important to KeySpan,  is the evolution of regulatory policy as it pertains
to our historical  gas merchant  role. In addition,  we are exposed to commodity
price risk,  interest  rate risk and, to a much less  degree,  foreign  currency
translation  risk.  Set forth below is a description  of these  exposures and an
explanation  as to how we have  managed and, to the extent  possible,  sought to
reduce these risks.

Regulatory Issues and the Competitive Environment

The Gas Industry

The energy industry continues to undergo fundamental  changes,  which may have a
significant  impact  on  the  future  financial  performance  of  utilities,  as
regulatory authorities, elected officials and customers seek lower energy prices
and broader choices.

New York

Over the past several years,  the NYPSC has been  formulating a policy framework
to guide the  transition  of New York State's gas  distribution  industry in the
deregulated gas industry environment.  Since 1996, customers in the small-volume
market have been given the option to purchase  their gas  supplies  from sources
other than our two New York gas utility subsidiaries. Large-volume customers had
this option for a number of years prior to 1996. In addition to transporting gas
that  customers  purchase  from  marketers,  our utilities  have been  providing
billing,  meter reading and other  services for  aggregate  rates that match the
distribution  charge  reflected  in otherwise  applicable  sales rates to supply
these customers.

In November 1998, the NYPSC issued a policy  statement  setting forth its vision
for  furthering  competition  in the natural gas  industry.  Under this  vision,
regulated natural gas utilities or local  distribution  companies ("LDCs") would
plan to exit the  business of  purchasing  gas for and selling gas to  customers
(the merchant  function)  over the next three to seven years.  LDCs would remain
the operators of the gas system (the distribution  function) and the provider of
last resort of natural gas  supplies  during that period and until  alternatives
are developed.  The NYPSC's goal is to encourage  more  competition at the local
level by separating the merchant function from the distribution function.

As required by the NYPSC's policy  statement,  our two New York gas distribution
subsidiaries  filed a joint  restructuring  proposal  with the NYPSC in  October
1999. Settlement discussions

                                       34

<PAGE>



with the Staff of the NYPSC and other interested parties were held regarding the
joint  restructuring  proposal.  Those  discussions  resulted  in an Interim Gas
Restructuring  Agreement  which the  NYPSC  approved  in its Order  Establishing
Interim  Rate Plan  ("Interim  Agreement"),  issued on December  26,  2000.  The
Interim  Agreement as approved  provided that,  among other things:  (i) present
base rates will remain  unchanged;  (ii) heating  customers  will receive a one-
time bill  credit of $50 to offset  gas  commodity  prices  during the winter of
2001; and (iii)  marketers will receive an incentive  payment equal to 8% of the
delivery charges marketers incur to serve firm customers to encourage  marketers
to provide gas commodity sales to our customers.  Both the $50 credit and the 8%
incentive  payment will be  deferred,  and the formula for recovery of potential
stranded capacity costs will be modified to maintain a more stable allocation of
fixed costs between sales and transportation  services.  The term of the Interim
Agreement  expires on June 30,  2001,  and also  provides  that the parties will
resume  negotiations  on  issues  that  were  not  resolved,   including,  daily
balancing,  a  migration  program  for  cooking-  only  customers,  a low income
customer  aggregation  program,  and a back out  credit to be  applied  to rates
charged to customers who migrate to a non-utility energy supplier. We, the Staff
of the NYPSC and other interested  parties have begun discussions to address the
issues remaining in the case.

New England

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

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


                                       35

<PAGE>



The Electric Industry in New York and Long Island

As previously  mentioned,  our electric  operations on Long Island are generally
governed by service  agreements with LIPA. The agreements have terms of eight to
fifteen  years and  generally  provide for  recovery of  virtually  all costs of
production, operation and maintenance. At this time, we face minimal competitive
pressures associated with our electric operations on Long Island.

With our investment in the Ravenswood facility, we also have electric operations
in New York City.  We  currently  sell the  energy  produced  by the  Ravenswood
facility, as well as its capacity,  through daily and/or hourly bidding into the
NYISO energy markets.  New York City local  reliability  rules currently require
that 80% of the  electric  capacity  needs of New York City is to be provided by
"in-city" generators.  At this time, there is a shortage of in-city capacity and
therefore,  we  anticipate  that we can  sell  the  capacity  of the  Ravenswood
facility at a level  approaching the FERC mandated price cap. We expect that the
current local  reliability  rules will remain in effect at least through October
31, 2001. However,  should new, more efficient electric power plants be built in
New York City  and/or  the  requirement  that 80% of  in-city  load be served by
in-city  generators  be modified,  capacity and energy  sales  volumes  could be
adversely affected. We cannot predict, however, when or if new power plants will
be built or the nature of future New York City requirements.

California Deregulation

In the late 1990's, the California Public Utilities  Commission ("CPUC") ordered
the state's electric  utilities to divest their generation  assets, and purchase
their  electricity  supply from the California  Power Exchange (PX) on a spot or
short term basis. In addition,  the electric utilities were subjected to caps on
the prices they charged their  customers at retail.  No provisions  were made in
the CPUC's orders or the restructuring  agreements entered into by the utilities
and other  parties to reopen the retail  rate issue in the event the  utilities'
financial integrity became jeopardized.

Within  the  last  year,   wholesale   electricity  supply  levels  have  become
insufficient to meet demand, spot market prices have increased, and retail rates
are now  insufficient  to compensate  the utilities for their  wholesale  supply
costs, causing severe financial disruptions for those utilities.

In contrast, our gas distribution subsidiaries maintain flexibility in their gas
procurement  policies  and  practices  and  are not  required  to  purchase  gas
commodity or capacity in any specific  manner as long as the  purchases are made
on a least cost basis. Our gas distribution subsidiaries also operate under rate
regulated  cost  recovery  mechanisms  associated  with their  retail rates that
provide for recovery of costs on a current and deferred basis. In the event that
our gas distribution  subsidiaries' financial integrity were jeopardized,  there
is a provision in their currently  effective rate plans that would allow for the
reexamination  of their  retail rate  structure.  With  regards to our  electric
service operations, as previously indicated,  under our LIPA service agreements,
virtually  all  costs  of  production,   operation  and  maintenance  are  being
recovered.

                                       36

<PAGE>



In addition, due to New York City local reliability rules, we anticipate that we
can sell a significant  portion of the capacity  associated  with the Ravenswood
facility.  Moreover, we are currently recovering 100% of our electric fuel costs
and expect to continue to recover these costs through sales into the NYISO.

Derivative Financial Instruments

As previously mentioned,  and more fully detailed in Note 10 to the Consolidated
Financial  Statements,  "Hedging,  Derivative  Financial  Instruments  and  Fair
Values," we employ derivative  instruments to hedge a portion of our exposure to
commodity  price risk and interest  rate risk and to fix the selling  price on a
portion of our peak electric energy  capacity.  All of our derivative  financial
instruments, except for certain interest rate swaps, are and will continue to be
classified  as cash-flow  hedges and expire in 2001.  As a result,  Statement of
Financial  Accounting  Standards  ("SFAS") No. 133,  "Accounting  for Derivative
Instruments and Hedging Activities" is not expected to have a material effect on
our net income in 2001,  but could have a  significant  effect on  comprehensive
income because of fluctuations  in the market value of the derivatives  employed
for hedging certain risks.  Under SFAS No. 133, periodic changes in market value
are  recorded  as  comprehensive  income,  subject  to  effectiveness,  and then
included in net income to match the underlying transactions.

Futures,  Options and Swaps: We employ, from time to time,  derivative financial
instruments,  such as  futures,  options  and swaps,  for the purpose of hedging
exposure to  commodity  price risk and to fix the selling  price on a portion of
our peak electric energy capacity.

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,  as  the  instrument  contracts  are  with  major
investment grade financial  institutions,  and that reduction of the exposure to
price risk lowers our overall business risk.

Interest Rate Hedges: We continually monitor the cost relationship between fixed
and variable rate debt. In line with our objective to minimize capital costs, we
periodically  enter into hedging  transactions  through interest rate swaps that
effectively  convert the terms of the underlying debt  obligations from fixed to
variable  and/or  variable to fixed.  Swap agreements are only entered into with
creditworthy counter parties.









                                       37

<PAGE>



Foreign Currency Fluctuations

We follow the  principles of SFAS No. 52,  "Foreign  Currency  Translation"  for
recording our investments in foreign affiliates. Due to our purchases of certain
Canadian  interests  and our  continued  activities  in  Northern  Ireland,  our
investment in foreign affiliates has been growing. At December 31, 2000, our net
assets in these affiliates was approximately  $347.6 million and at December 31,
2000, the accumulated foreign currency translation debit was $2.3 million.  (See
Note  1 to  the  Consolidated  Financial  Statements,  "Summary  of  Significant
Accounting Policies.")

                                       38

<PAGE>

Item 8. Financial Statements and Supplementary Data

Financial Statement Responsibility

KeySpan's and its subsidiaries'  Consolidated Financial Statements were prepared
by management in conformity with generally accepted accounting principles.

KeySpan's  system  of  internal  controls  is  designed  to  provide  reasonable
assurance  that assets are  safeguarded  and that  transactions  are executed in
accordance with management's  authorizations  and recorded to permit preparation
of financial statements that present fairly the financial position and operating
results of KeySpan.  KeySpan's internal auditors evaluate and test the system of
internal  controls.  The Company's  Vice President and General  Auditor  reports
directly to the Audit  Committee  of the Board of  Directors,  which is composed
entirely of outside  directors.  The Audit  Committee  meets  periodically  with
management,  the Vice President and General  Auditor and Arthur  Andersen LLP to
review and discuss  internal  accounting  controls,  audit  results,  accounting
principles and practices and financial reporting matters.

<TABLE>

                                                   CONSOLIDATED BALANCE SHEET
                                                    (In Thousands of Dollars)
<CAPTION>


                                                                                 December 31, 2000           December 31, 1999
--------------------------------------------------------------------------------------------------------------------------------


ASSETS
<S>                                                                                  <C>                        <C>
Current Assets
    Cash and temporary cash investments                                $                 94,508     $              128,602
    Customer accounts receivable                                                      1,471,102                    425,643
    Other accounts receivable                                                           300,198                    235,156
    Allowance for uncollectible accounts                                                (49,478)                   (20,294)
    Gas in storage, at average cost                                                     282,654                    144,256
    Materials and supplies, at average cost                                             123,608                     84,813
    Other                                                                               180,651                    159,777
                                                                             ------------------        -------------------
                                                                                      2,403,243                  1,157,953
                                                                             ------------------        -------------------


Equity Investments and Other                                                            199,196                    391,731
                                                                             ------------------        -------------------

Property
    Gas                                                                               5,346,799                  3,449,384
    Electric                                                                          1,412,839                  1,346,851
    Other                                                                               734,801                    375,657
    Accumulated depreciation                                                         (2,301,722)                (1,589,287)
    Gas exploration, production and refining                                          1,781,379                  1,177,916
    Accumulated depletion                                                              (615,799)                  (520,509)
                                                                             ------------------        -------------------
                                                                                      6,358,297                  4,240,012
                                                                             ------------------        -------------------

Deferred Charges
    Regulatory assets                                                                   385,116                    319,167
    Goodwill, net of amortizations                                                    1,848,721                    255,778
    Other                                                                               355,548                    366,050
                                                                             ------------------        -------------------
                                                                                      2,589,385                    940,995
                                                                             ------------------        -------------------

                                                                             ------------------        -------------------
Total Assets                                                           $             11,550,121     $            6,730,691
                                                                             ==================        ===================
</TABLE>






               See accompanying Notes to the Consolidated Financial Statements.



                                       39

<PAGE>


<TABLE>
                                                   CONSOLIDATED BALANCE SHEET
                                                    (In Thousands of Dollars)

<CAPTION>
                                                                                    December 31, 2000          December 31, 1999
------------------------------------------------------------------------------------------------------------------------------------


LIABILITIES AND CAPITALIZATION
<S>                                                                                      <C>                       <C>
Current Liabilities
     Current redemption of long-term debt                              $                       5,480    $                    -
    Current redemption of preferred stock                                                          -                   363,000
    Accounts payable and accrued expenses                                                  1,429,267                   645,347
    Commercial paper                                                                       1,300,237                   208,300
    Dividends payable                                                                         62,218                    61,306
    Taxes accrued                                                                             74,614                    50,437
    Customer deposits                                                                         32,855                    31,769
    Interest accrued                                                                          69,402                    28,093
                                                                              ----------------------       -------------------
                                                                                           2,974,073                 1,388,252
                                                                              ----------------------       -------------------

Deferred Credits and Other Liabilities
    Regulatory liabilities                                                                    34,486                    26,618
    Deferred income tax                                                                      451,721                   188,930
    Postretirement benefits and other reserves                                               662,866                   501,603
    Other                                                                                    126,818                    66,200
                                                                              ----------------------       -------------------
                                                                                           1,275,891                   783,351
                                                                              ----------------------       -------------------

Capitalization
    Common stock                                                                           2,985,022                 2,973,388
    Retained earnings                                                                        480,639                   456,882
    Other Comprehensive Income                                                                   825                     5,014
    Treasury stock purchased                                                                (650,670)                 (722,959)
                                                                              ----------------------       -------------------
      Total common shareholders' equity                                                    2,815,816                 2,712,325
    Preferred stock                                                                           84,205                    84,339
    Long-term debt                                                                         4,274,938                 1,682,702
                                                                              ----------------------       -------------------
Total Capitalization                                                                       7,174,959                 4,479,366
                                                                              ----------------------       -------------------

Minority Interest in Subsidiary Companies                                                    125,198                    79,722
                                                                              ----------------------       -------------------
Total Liabilities and Capitalization                                   $                  11,550,121    $            6,730,691
                                                                              ======================       ===================
</TABLE>


                See accompanying Notes to the Consolidated Financial Statements.



                                       40

<PAGE>


<TABLE>
<CAPTION>
                                                CONSOLIDATED STATEMENT OF INCOME
                                       (In Thousands of Dollars, Except Per Share Amounts)

                                                                           Year                      Year              Nine Months
                                                                           Ended                     Ended                Ended
                                                                        December 31,              December 31,         December 31,
                                                                           2000                      1999                 1998
---------------------------------------------------------------- ------------------------- ---------------------- ------------------
<S>                                                                       <C>                     <C>                  <C>
Revenues
Gas Distribution                                                    $       2,555,785   $          1,753,132       $      856,172
Electric Services                                                           1,444,711                861,582              738,316
Gas Exploration and Production                                                274,209                150,581               70,812
Energy Services                                                               771,861                186,529               63,064
Energy Investments and Other                                                   74,924                  2,789                  117
                                                                      ---------------       ----------------        -------------
Total Revenues                                                              5,121,490              2,954,613            1,728,481
                                                                      ---------------       ----------------        -------------
Operating Expenses
Purchased gas for resale                                                    1,408,621                744,432              331,690
Fuel and purchased power                                                      460,900                 17,252               91,762
Operations and maintenance                                                  1,695,507              1,091,166              777,678
Early retirement and severance charges                                         65,175                      -               64,635
Depreciation, depletion and amortization                                      335,106                253,440              254,859
Operating taxes                                                               424,318                366,154              257,124
                                                                      ---------------       ----------------        -------------
Total Operating Expenses                                                    4,389,627              2,472,444            1,777,748
                                                                      ---------------       ----------------        -------------
Operating Income (Loss)                                                       731,863                482,169              (49,267)
                                                                      ---------------       ----------------        -------------

Other Income and (Deductions)
Income from equity investments                                                 20,010                 15,347                5,841
Interest income                                                                13,190                 26,993               50,104
Transaction related expenses (net of $99,701 income tax)                            -                      -             (107,912)
Minority interest                                                            (26,342)               (11,141)               29,141
Other                                                                        (18,288)                 15,356              (13,901)
                                                                      ---------------       ----------------        -------------
Total Other Income                                                           (11,430)                 46,555              (36,727)
                                                                      ---------------       ----------------        -------------
Income (Loss) Before Interest Charges
  and Income Taxes                                                            720,433                528,724              (85,994)
                                                                      ---------------       ----------------        -------------

Interest Charges                                                              203,350                133,751              140,733
                                                                      ---------------       ----------------        -------------

Income Taxes
    Current                                                                   169,823                 26,618               26,142
    Deferred                                                                   46,453                109,744              (85,936)
                                                                      ---------------       ----------------        -------------
Total Income Taxes                                                            216,276                136,362              (59,794)
                                                                      ---------------       ----------------        -------------

Net Income (Loss)                                                             300,807                258,611             (166,933)
Preferred stock dividend requirements                                          18,113                 34,752               28,604
                                                                      ---------------       ----------------        -------------
Earnings (Loss) for Common Stock                                    $         282,694    $           223,859     $       (195,537)
                                                                      ===============       ================        =============

Average Common Shares Outstanding (000)                                       134,357                138,526              145,767
                                                                    $                    $                       $
Basic and Diluted Earnings (Loss) Per Common Share                               2.10                   1.62               (1.34)
                                                                      ===============       ================        =============
</TABLE>

                See accompanying Notes to the Consolidated Financial Statements.


                                       41

<PAGE>


<TABLE>
                      CONSOLIDATED STATEMENT OF CASH FLOWS
<CAPTION>
                            (In Thousands of Dollars)

                                                                                                                     Nine Months
                                                                           Year Ended           Year Ended               Ended
                                                                          December 31,          December 31,         December 31,
                                                                              2000                 1999                  1998

------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>                  <C>                <C>
Operating Activities
Net Income (Loss)                                                    $          300,807         $   258,611     $      (166,933)
Adjustments to reconcile net income to net
           cash provided by (used in) operating activities
      Depreciation, depletion and amortization                                  335,106             253,440              254,859
      Early retirement and severance accruals                                    65,175                   -               64,635
      Deferred income tax                                                        46,453             109,744             (85,936)
      Income from equity investments                                            (20,010)            (15,347)             (5,841)
      Dividends from equity investments                                          21,507               9,368                4,219
Changes in assets and liabilities
      Accounts receivable                                                      (800,033)           (132,114)            (81,024)
      Materials and supplies, fuel oil and  gas in storage                      (36,952)             (9,789)            (63,195)
      Accounts payable and accrued expenses                                     452,076              83,493              132,028
      Interest accrued                                                           32,659               8,128            (151,268)
      Special deposits                                                           17,896              52,373             (41,040)
      Other                                                                      35,221             (28,902)           (320,792)
                                                                   --------------------   -----------------   ------------------
Net Cash Provided by (Used in) Operating Activities                             449,905             589,005            (460,288)
                                                                   --------------------   -----------------   ------------------

Investing Activities
Construction expenditures                                                      (633,035)           (671,845)           (676,563)
Other Investments                                                              (292,222)            (53,825)                   -
Acquisition of Eastern Enterprise and EnergyNorth, Inc.                      (1,946,043)                  -                    -
Net Proceeds from LIPA Transaction                                                    -                   -            2,314,588
Other                                                                              (510)             30,006              178,634
                                                                   --------------------   -----------------   ------------------
Net Cash (Used in) Provided by Investing Activities                          (2,871,810)           (695,664)           1,816,659
                                                                   --------------------   -----------------   ------------------

Financing Activities
Proceeds from sale of common stock                                                    -                   -               10,170
Treasury stock issued  (purchased)                                               72,289            (299,243)           (423,716)
Issuance of long-term debt                                                    2,166,955             102,648              112,535
Issuance of commercial paper                                                  1,300,237             208,300                    -
Payment of commercial paper                                                    (364,865)                  -                    -
Payment of long-term debt                                                       (68,365)           (442,475)           (103,000)
Issuance of preferred stock                                                           -                   -               84,973
Payment of preferred stock                                                     (363,000)                  -                    -
Preferred stock dividends paid                                                  (20,261)            (34,760)            (28,604)
Common stock dividends paid                                                    (239,740)           (249,567)           (210,177)
Settlement on interest rate lock                                                (59,490)                  -                    -
Other                                                                           (35,949)              7,582             (36,695)
                                                                   --------------------   -----------------   ------------------
Net Cash Provided by (Used in) Financing Activities                           2,387,811            (707,515)           (594,514)
                                                                   --------------------   -----------------   ------------------
Net (Decrease) or Increase in Cash and Cash Equivalents              $          (34,094)     $     (814,174)    $        761,857
                                                                   ====================   =================   ==================
Cash and cash equivalents at beginning of period                     $          128,602      $      942,776     $        180,919
Net (Decrease) or Increase in cash and cash equivalents                         (34,094)           (814,174)             761,857
                                                                   --------------------   -----------------   ------------------
Cash and Cash Equivalents at End of Period                           $           94,508      $      128,602     $        942,776
                                                                   ====================   =================   ==================
Interest paid                                                        $          165,020      $      109,614     $        125,914
Income tax paid                                                      $          187,219      $       38,700     $         94,680
</TABLE>
                See accompanying Notes to the Consolidated Financial Statements.

                                       42

<PAGE>



<TABLE>
<CAPTION>
                                           CONSOLIDATED STATEMENT OF RETAINED EARNINGS
                                                    (In Thousands of Dollars)

                                                                                                                      Nine Months
                                                              Year Ended                 Year Ended                      Ended
                                                             December 31,            December 31, 1999             December 31, 1998
                                                                 2000
-----------------------------------------------------  ------------------------  -------------------------- ------------------------
<S>                                                           <C>                         <C>                            <C>
Balance at Beginning of Period                         $       456,882          $          474,188         $               956,092
Net Income (loss) for period                                   300,807                     258,611                        (166,933)
                                                       ------------------------  -------------------------- ------------------------
                                                               757,689                     732,799                         789,159
Deductions:
Cash dividends declared on common stock                        239,740                     246,251                         214,012
Cash dividends declared on preferred stock                      20,298                      34,752                          28,604
Other, primarily write-off of
       capital stock expense                                    17,012                      (5,086)                         72,355
                                                       ------------------------  -------------------------- ------------------------
Balance at End of Period                               $       480,639          $          456,882         $               474,188
-----------------------------------------------------  ------------------------  -------------------------- ------------------------
</TABLE>

<TABLE>
<CAPTION>
                                         CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
                                                    (In Thousands of Dollars)

                                                                                                                      Nine Months
                                                                    Year Ended               Year Ended                  Ended
                                                                December 31, 2000         December 31, 1999        December 31, 1998
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>                    <C>                      <C>
Net Income                                                  $          300,807 $              258,611  $              (166,933)
                                                            ------------------ ----------------------  -------------------------
Other comprehensive income (loss), net of tax
    Foreign currency translation adjustments                            (7,320)                 5,633                     (619)
    Unrealized gains on securities                                       3,131                      -                        -
                                                            ------------------ ----------------------  -------------------------
Other comprehensive income (loss)                                       (4,189)                 5,633                     (619)
                                                            ------------------ ----------------------  -------------------------
Comprehensive income                                        $          296,618 $              264,244  $              (167,552)
----------------------------------------------------------  ------------------ ----------------------  -------------------------
Related tax (benefit) expense
    Foreign currency translation adjustments                $           (3,941)$                3,033  $                  (333)
    Unrealized gains on securities                                       1,686                      -                        -
                                                            ------------------ ----------------------  -------------------------
Total tax (benefit) expense                                 $           (2,255)$                3,033  $                  (333)
----------------------------------------------------------  ------------------ ----------------------  -------------------------
</TABLE>











                See accompanying Notes to the Consolidated Financial Statements.


                                       43

<PAGE>


<TABLE>
<CAPTION>
                                            CONSOLIDATED STATEMENT OF CAPITALIZATION


                                                                    Shares Issued                          (In Thousands of Dollars)
-------------------------------------------------- --- -----------------------------------------------------------------------------
                                                           December 31,         December 31,        December 31,        December 31,
                                                               2000                 1999                2000                1999
-------------------------------------------------- --- -----------------------------------------------------------------------------
<S>                                                     <C>               <C>                       <C>                  <C>
Common Shareholder's Equity
Common Stock, $0.01 par value                               158,837,654         158,837,654    $          1,588    $           1,588
Premium on capital stock                                                                              2,983,434            2,971,800
Retained Earnings                                                                                       480,639              456,882
Other Comprehensive Income                                                                                  825                5,014
Treasury Stock                                               22,474,628          24,971,577           (650,670)            (722,959)
                                                       ----------------  ------------------       -------------       --------------
Total Common Shareholder's Equity                           136,363,026         133,866,077           2,815,816            2,712,325
                                                       ----------------  ------------------       -------------       --------------

Preferred Stock - Redemption Required
Par Value $25 per share
     7.95% Series AA                                                  -          14,520,000                   -              363,000
Less - mandatory redemption of preferred stock                                                                -              363,000
                                                                                                  -------------       --------------
Total Preferred Stock - Redemption Required                                                                   -                    -
                                                                                                  -------------       --------------

Preferred Stock - No Redemption Required
Par Value $100 per share
     7.07% Series B-private placement                           553,000             553,000              55,300               55,300
     7.17% Series C-private placement                           197,000             197,000              19,700               19,700
     6.00% Series A-private placement                            92,050              93,390               9,205                9,339
                                                                                                  -------------       --------------
Total Preferred Stock -
      No Redemption Required                                                                             84,205               84,339
                                                                                                  -------------       --------------

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

First Mortgage Bonds                                      5.50% - 10.10%         2002-2028              322,872                    -
                                                                                                 ------------------  ---------------
Notes
     Medium Term Notes                                    6.80% - 9.75%          2005-2030            2,260,000                    -
     Senior Subordinated Notes                                8.625%                2008                100,000              100,000
                                                                                                 ------------------  ---------------
Total Notes                                                                                           2,360,000              100,000
                                                                                                 ------------------  ---------------

Gas Facilities Revenue Bonds                                 Variable               2020                125,000             125,000
                                                          5.50% - 6.95%          2020-2026              523,500             523,500
                                                                                                 ------------------  ---------------
Total Gas Facilities Revenue Bonds                                                                      648,500             648,500
                                                                                                 ------------------  ---------------

Authority Financing Notes                                    Variable            2027-2028               66,005              66,005
                                                                                                 -----------------   ---------------

Promissory Notes to LIPA
     Debentures                                               8.20%                 2023                270,000             270,000
     Pollution Control Revenue Bonds                          5.15%                 2016                108,022             108,022
     Electric Facilities Revenue Bonds                    5.30% - 7.15%          2019-2025              224,405             224,405
                                                                                                 -----------------   ---------------
Total Promissory Notes to LIPA                                                                          602,427             602,427
                                                                                                 ----------------    ---------------

Other Subsidiary Debt                                                                                   328,227             267,405
                                                                                                 ----------------    ---------------

Capital Leases                                                                   2008-2020               22,005                   -
                                                                                                 ----------------    ---------------

Subtotal                                                                                              4,350,036           1,684,337
     Unamortized Interest Rate Hedge
        and Debt Discount                                                                              (69,618)             (1,635)
     Less Current Maturities                                                                              5,480                   -
                                                                                                 -----------------  ----------------
Total Long Term Debt                                                                                  4,274,938           1,682,702
                                                                                                 -----------------  ----------------
Total Capitalization                                                                               $  7,174,959    $      4,479,366
                                                                                                 =================  ================
</TABLE>
                See accompanying Notes to the Consolidated Financial Statements.

                                                                 44

<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,  we  acquired  Eastern  Enterprises
("Eastern"),  a  Massachusetts  business  trust,  and the parent of several  gas
utilities operating in Massachusetts. Also on November 8, 2000, Eastern acquired
EnergyNorth,  Inc. ("ENI"), the parent of a gas utility operating in central New
Hampshire.  KeySpan  Corporation  will be  referred  to in  these  notes  to the
Consolidated Financial Statements as "KeySpan", "we", "us" and "our."

Our core  business  is gas  distribution,  conducted  by our six  regulated  gas
utility  subsidiaries:  The  Brooklyn  Union Gas Company  d/b/a  KeySpan  Energy
Delivery  New York  ("KEDNY")  and KeySpan Gas East  Corporation  d/b/a  KeySpan
Energy  Delivery  Long  Island  ("KEDLI")  distribute  gas to  customers  in the
boroughs of Brooklyn, Queens and Staten Island in New York City and the counties
of Nassau and Suffolk on Long Island, 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 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 2.4 million customers
throughout the Northeast.

We also own and operate  generating  plants on Long Island and in New York City.
Under  contractual  arrangements,  we provide power,  electric  transmission and
distribution services, billing and other customer services for approximately one
million  electric  customers of the Long Island Power Authority  ("LIPA").  (See
Note 2,  "Business  Segments"  for  additional  information  on  each  operating
segment.)

Our other  subsidiaries  are involved in gas and oil exploration and production;
gas storage; wholesale and retail gas and electric marketing; appliance service;
heating,  ventilation  and air  conditioning  installation  and services;  large
energy-system  ownership,  installation  and  management;  fiber optic services;
energy-related internet activities; fuel cells; marine transportation, including
the barge hauling of fuel and other cargo; and providing meter reading equipment
and services to municipal  utilities.  We also invest in, and participate in the
development of, pipelines and other  energy-related  projects,  domestically and
internationally.

We are a registered holding company under the Public Utility Holding Company Act
of 1935 ("PUHCA"), as amended. Therefore, our corporate and financial activities
and those of our  subsidiaries,  including their ability to pay dividends to us,
are subject to regulation by the  Securities  and Exchange  Commission  ("SEC").
Under our holding company structure, we have no

                                       45

<PAGE>



independent  operations or source of income of our own and conduct substantially
all of our operations  through our subsidiaries  and, as a result,  we depend on
the  earnings  and cash  flow of,  and  dividends  or  distributions  from,  our
subsidiaries  to provide the funds  necessary  to meet our debt and  contractual
obligations.  Furthermore,  a substantial  portion of our  consolidated  assets,
earnings and cash flow is derived from the  operations of our regulated  utility
subsidiaries, whose legal authority to pay dividends or make other distributions
to us is subject to regulation by state regulatory authorities.

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 Investment 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 investee companies. All significant intercompany transactions
have been eliminated.

Certain reclassifications were made to conform prior period financial statements
with the current period financial statement presentation.

The financial  statements  presented  herein include the year ended December 31,
2000,  the year ended December 31, 1999, and the nine month period April 1, 1998
through December 31, 1998 (the  "Transition  Period").  For financial  reporting
purposes,  LILCO  was  deemed  the  acquiring  company  pursuant  to a  purchase
accounting transaction, in which KeySpan Energy Corporation ("KSE") was acquired
("KeySpan  Acquisition").  Consequently,  our financial results prior to May 29,
1998  reflect  those of LILCO  only.  Since the  acquisition  of KeySpan  Energy
Corporation  was accounted for as a purchase,  related  accounting  adjustments,
including  goodwill,  have been  reflected in the financial  statements  herein.
Further,  in  September  1998,  we changed  our fiscal year end from March 31 to
December 31. For additional information regarding the KeySpan acquisition.  (See
Note 15. "Sale of LILCO Assets,  Acquisition of KeySpan Energy  Corporation  and
Transfer of Assets and Liabilities to KeySpan.")

As noted,  on  November  8,  2000,  we  completed  the  acquisitions  of Eastern
Enterprises   ("Eastern")  and  EnergyNorth  Inc.  The  transactions  have  been
accounted for using the purchase method of accounting for business  combinations
and accordingly the accompanying  consolidated  financial statements include the
results of Eastern and ENI for the period November 8, 2000 through  December 31,
2000.

The preparation of financial  statements in conformity  with generally  accepted
accounting principles 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.


                                       46

<PAGE>



C.  Accounting for the Effects of Rate Regulation

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

Four of our six regulated gas utilities  (KEDNY,  KEDLI,  Boston Gas Company and
EnergyNorth  Natural Gas,  Inc.) and our electric  generation  subsidiaries  are
subject  to the  provisions  of  Statement  of  Financial  Accounting  Standards
("SFAS") No. 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, respectively.

In separate  merger-related  orders issued by the DTE, the base rates charged by
Colonial  Gas Company and Essex Gas  Company  have been frozen at their  current
levels for a ten-year  period.  Due to the length of this base rate freeze,  the
Colonial and Essex Gas Companies have previously discontinued the application of
SFAS No. 71.

The following table presents our net regulatory  assets at December 31, 2000 and
December 31, 1999.
<TABLE>
<CAPTION>

                                                      (In Thousands of Dollars)
-----------------------------------------------------------------------------------------------------------
                                                               December 31, 2000          December 31, 1999
--------------------------------------------------------  -------------------- ----------------------------
<S>                                                                  <C>                      <C>
Regulatory Assets
   Regulatory tax asset                                   $            61,071      $            65,462
   Property taxes                                                      51,948                   40,434
   Environmental costs                                                116,609                   95,627
   Postretirement benefits other than pensions                         89,188                   48,553
   Costs associated with the KeySpan Acquisition                       66,300                   69,091
                                                           ------------------       ----------------------
Total Regulatory Assets                                   $           385,116      $           319,167
Regulatory Liabilities                                                 34,486                   26,618
                                                           ------------------       ----------------------
Net Regulatory Assets                                     $           350,630      $           292,549
--------------------------------------------------------   ------------------       ----------------------
</TABLE>
The  regulatory  assets  above are not  included in our rate base.  However,  we
record  carrying  charges  on the  property  tax and costs  associated  with the
KeySpan Acquisition deferrals. We also record carrying charges on our regulatory
liability. The remaining regulatory assets represent, primarily, costs for which
expenditures have not yet been made, and therefore, carrying charges are not

                                       47

<PAGE>



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 $189.8  million and $1.2  million at December 31, 2000 and December
31, 1999,  respectively are reflected in accounts receivable on the Consolidated
Balance Sheet.

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

Rate  regulation is undergoing  significant  change as regulators  and customers
seek lower  prices for  utility  service and greater  competition  among  energy
service  providers.  In the event  that  regulation  significantly  changes  the
opportunity  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
No.  71.  In that  event,  a  write-down  of all or a  portion  of our  existing
regulatory  assets  and  liabilities  could  result.  If we had been  unable  to
continue to apply the  provisions  of SFAS No. 71 for any of our rate  regulated
subsidiaries,  we would have applied the  provisions of SFAS No. 101  "Regulated
Enterprises  -  Accounting  for  the  Discontinuation  of  Application  of  FASB
Statement  No. 71." We estimate  that the  write-off  of all our net  regulatory
assets at  December  31,  2000 could  result in a charge to net income of $227.9
million or $1.70 per share, which would be classified as an extraordinary  item.
In management's  opinion, our regulated  subsidiaries that are currently subject
to the  provisions of SFAS No. 71 will continue to be subject to SFAS No. 71 for
the foreseeable future.

D.  Revenues

Utility gas  customers  are billed  monthly  and  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 an annual  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.  The New England gas utility  rate  structures
contain no weather  normalization  feature,  therefore  their net  revenues  are
subject to weather related demand fluctuations.



                                       48

<PAGE>



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

In addition,  electric  revenues are derived  from our  investment  in the 2,200
megawatt Ravenswood electric generation facility ("Ravenswood facility"),  which
we  acquired  in  June  1999.   (See  Note  9,   "Contractual   Obligations  and
Contingencies"  for a description of the Ravenswood  transaction.)  We currently
realize  revenues from our  investment in the  Ravenswood  facility  through the
wholesale  sale of energy,  capacity,  and  ancillary  services  to the New York
Independent System Operator ("NYISO").  Energy,  capacity and ancillary services
are sold through a bidding  process into the NYISO energy markets on a day ahead
or real  time  basis.  Prior to the  start of the NYISO on  November  19,  1999,
however,   KeySpan  and   Consolidated   Edison   Company  of  New  York,   Inc.
("Consolidated  Edison") entered into transition energy and capacity  contracts.
The  energy  contract  provided  Consolidated  Edison  with  100% of the  energy
produced by the  Ravenswood  facility on a cost  recovery  basis.  This contract
expired on November 19, 1999. The capacity contract provided Consolidated Edison
with 100% of the  available  capacity  of the  Ravenswood  facility on a monthly
fixed-fee basis. This contract expired on April 30, 2000.

Revenues  earned by our Energy  Services  segment for the design,  building  and
installation of heating, ventilation and air-conditioning systems are recognized
by the percentage of completion  method.  This method measures the percentage of
costs  incurred  and accrued to date for each  contract to the  estimated  total
costs for each  contract  at  completion.  Provisions  for  estimated  losses on
uncompleted contracts are made in the period such losses are determined. Changes
in job  performance,  job conditions and estimated  profitability  may result in
revisions to cost and income,  which are  recognized in the period the revisions
are determined.

E.  Utility Property - Depreciation and Maintenance

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.  Electric  depreciation  consists of  depreciation  of our
electric generating facilities,  including the Ravenswood facility from June 19,
1999.



                                       49

<PAGE>



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

                     Period                             Electric           Gas
                     ------                             --------           ---
           Year Ended December 31, 2000                  3.68%             3.51%
           Year Ended December 31, 1999                  3.56%             2.85%
           Nine Months Ended December 31, 1998           2.54%             2.07%


F.  Gas Exploration and Production Property - Depletion

The full cost method of  accounting is used for  investments  in natural gas and
oil properties.  Under this 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 the ratio of current
production to total proved natural gas and oil reserves. 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,  such  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 from  operating  activities.  Once  incurred,  such
impairment  of gas  properties  is not  reversible  at a later  date even if gas
prices increase.  In December 1998, The Houston  Exploration  Company  ("Houston
Exploration"),  our 70% owned gas and oil exploration and production subsidiary,
recorded a $130 million write-down to its investment in its proved gas reserves,
which is reflected in the accompanying financial statements.

As of December 31, 2000, Houston Exploration  estimates,  using prices in effect
as of such date, that the ceiling  limitation imposed under full cost accounting
rules exceeded actual capitalized costs.

G.  Goodwill

At  December  31,  2000,  we  have  goodwill  in the  amount  of  $1.8  billion,
representing  the excess of  acquisition  cost over the fair value of net assets
acquired.  Goodwill is amortized over 15 to 40 years. Our recorded goodwill, net
of accumulated amortizations, consists of approximately $1.5 billion relating to
the Eastern and ENI  acquisitions,  approximately  $160 million  relating to the
KeySpan Acquisition,  and approximately $190 million related to the acquisitions
of energy-related  services companies and to certain ownership  interests of 50%
or less in  energy-related  investments in Northern  Ireland which are accounted
for under the equity method.

H.  Hedging and Derivative Financial Instruments

Commodity  Derivatives:  We  employ,  from  time to time,  derivative  financial
instruments to hedge exposure in cash flows due to  fluctuations in the price of
natural gas that is used to serve our large  volume  customers  and used to fuel


                                       50

<PAGE>



our  Ravenswood  facility.  Our hedging  strategies  meet the criteria for hedge
accounting  treatment  under SFAS No. 80,  "Accounting  for Futures  Contracts."
Accordingly,  gains and losses on these instruments are recognized  concurrently
with the recognition of the related physical transactions. These derivatives are
considered cash-flow hedges.

We regularly  assess the  relationship  between natural gas commodity  prices in
"cash" and futures markets.  The correlation between prices in these markets has
been within a range generally  deemed to be acceptable.  If the correlation were
not to remain  in an  acceptable  range,  the  subsidiaries  would  account  for
financial instrument positions as trading activities.

Electric Derivatives:  We also utilize derivative instruments to fix the selling
price and "lock-in" a profit margin on a portion of our estimated electric sales
from the Ravenswood facility. We employ swap agreements in which we receive from
a counter party a fixed price per megawatt hour of electricity  sold and pay the
counter party the then floating market price for electric  supply.  Further,  we
have synthetic  tolling  arrangements  in which we receive a fixed margin from a
counter  party and then pay the counter  party our actual  profit  margin on the
sale of  electricity.  These  derivatives  are considered  cash-flow  derivative
instruments.

Interest Rate Derivatives:  We continually assess the cost relationship  between
fixed and variable  rate debt.  In line with our  objective to minimize  capital
costs, we periodically enter into hedging  transactions that effectively convert
the terms of underlying debt obligations  from fixed to variable.  Payments made
or received 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 considered fair-value 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.

J.  Income Tax

In accordance  with SFAS No. 109,  "Accounting  for Income Taxes" and applicable
rate regulation, certain of our regulated subsidiaries record a regulatory asset
for the net cumulative  effect of having to provide deferred income taxes on all
differences  between tax and book bases of assets and liabilities at the current
tax rate which have not yet been included in rates to customers.  Investment tax
credits, which were available prior to the Tax Reform Act of 1986, were deferred
and are  generally  amortized  as a reduction  of income tax over the  estimated
lives of the related property.

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.

                                       51

<PAGE>




L.  Foreign Currency Translation

We follow the principles of SFAS No. 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,  2000,  the  foreign  currency
translation  adjustment was included in other comprehensive income as a separate
component of shareholders' equity.

M.  Recent Accounting Pronouncements

In June 1999, the Financial  Accounting Standards Board ("FASB") issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective  Date of SFAS No. 133." SFAS No. 137 defers the effective  date of
SFAS No.  133 to fiscal  years  beginning  after  July 15,  2000.  SFAS No.  133
establishes  accounting and reporting  standards for derivative  instruments and
for hedging activities.

In June 2000, the FASB issued SFAS No. 138,  "Accounting for Certain  Derivative
Instruments and Certain  Hedging  Activities - An Amendment of FASB Statement No
133." SFAS No. 138 amends the accounting and reporting  standards of SFAS No.133
for a number of transactions.  The most significant amendment to SFAS No. 133 as
it relates to our  operations  is that the normal  purchase and sales  exception
found in SFAS  No.  133 may now be  applied  to  contracts  that  implicitly  or
explicitly permit net settlement,  and contracts that have a market mechanism to
facilitate net settlement  for which physical  delivery is probable.  Therefore,
under SFAS No. 138 our  present gas  procurement  contracts  are not  considered
derivative financial instruments.

All  of  our  derivative  financial  instruments  currently  qualify  for  hedge
accounting and, except for an interest rate swap, are cash-flow hedges. SFAS No.
133  requires  that an entity  recognize  all  derivatives  as either  assets or
liabilities in the statement of financial position and measure those instruments
at fair value.  Periodic  changes in market value of derivatives  which meet the
definition of a cash-flow hedge are recorded as comprehensive income, subject to
effectiveness,  and then included in net income to match the  underlying  hedged
transactions.  We adopted  SFAS No. 133 on January 1, 2001 and recorded a charge
to  comprehensive  income of $48.4 million.  Due to the transition  requirements
under SFAS No. 133 we did not incur a significant  charge to earnings for either
our cash flow hedges or fair value hedge upon initial application. Currently all
of our derivative  instruments  expire prior to the end of 2001 and therefore we
do not expect  SFAS No. 133 to have a material  effect on our net income for the
year ended  December  31,  2001.  However,  SFAS No. 133 may  continue to have a
significant effect on comprehensive income because of fluctuations in the market
value  of the  derivatives  we  employ.  Further,  depending  on  the  quarterly
measurement of hedging effectiveness,  SFAS No.133 may have a material effect on
our reported quarterly earnings.  (See Note 10, "Hedging,  Derivative  Financial
Instruments, and Fair Values" for additional information.)

                                       52

<PAGE>



The FASB  recently  issued a revision to its Exposure  Draft ("ED") on "Business
Combinations  and  Intangible  Assets".  In the ED, the FASB  concluded that the
amortization  of goodwill will no longer be required.  Instead,  companies  will
need to perform yearly  impairment  tests on the recorded amount of goodwill and
determine whether an impairment charge is necessary. The comment deadline on the
ED is March 16, 2001 and we believe the FASB will finalize its  deliberations on
goodwill  amortization  in  the  third  or  fourth  quarter  of  2001.  Goodwill
amortization for 2001 is estimated to be approximately $52 million. Depending on
the  timing of the final  statement,  we may  realize a  significant  benefit to
earnings in 2001 if we are required to discontinue the amortization of goodwill.
Such enhancement to earnings will not affect cash flow.

Note 2. Business Segments

We have six  reportable  segments:  Gas  Distribution,  Electric  Services,  Gas
Exploration and Production, Energy Services, Energy Investments and Other.

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,  Queens and Staten Island. KEDLI provides gas distribution
services to customers in the Long Island  counties of Nassau and Suffolk and the
Rockaway Peninsula of Queens County.  KEDNE provides 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,  all through long-term service contracts having remaining terms that
range from five to twelve  years.  The Electric  Services  segment also includes
subsidiaries that own, lease and operate the 2,200 megawatt  Ravenswood electric
generation facility, located in Queens, New York. Our contract with Consolidated
Edison,  which provided  Consolidated Edison with 100% of the available capacity
of the Ravenswood facility on a fixed monthly fee, expired on April 30, 2000. We
now provide all of the energy,  capacity and ancillary  services  related to the
Ravenswood  facility to the NYISO.  Currently,  our primary electric  generation
customers are LIPA and the NYISO energy markets.

The Gas Exploration and Production segment is engaged in gas and oil exploration
and production,  and the development and acquisition of domestic natural gas and
oil  properties.  This  segment  consists of our 70% equity  interest in Houston
Exploration,  an independent natural gas and oil exploration company, as well as
KeySpan Exploration and Production,  LLC, our wholly owned subsidiary engaged in
a joint venture with Houston  Exploration.  Effective December 31, 2000, KeySpan
and Houston  Exploration  mutually agreed that we will no longer  participate in
Houston Exploration's future offshore exploration  prospects.  We will, however,
continue to maintain our working  interest in all wells  drilled under the joint
venture  agreement.  We also agreed to continue the  development  of our working
interests in prospects drilled under the drilling program, and for 2001, we have
agreed to commit  approximately  $17 million for the  development  of  prospects
successfully  drilled  during  1999  and  2000.  On  March  31,  2000,  under  a
pre-existing credit

                                       53

<PAGE>



arrangement, approximately $80 million in debt owed by Houston Exploration to us
was converted into common equity of Houston  Exploration.  Upon such conversion,
our common equity ownership interest in Houston  Exploration  increased from 64%
to approximately 70%.

The Energy  Services  segment  includes  companies  that provide  energy-related
services to customers located within the New York City metropolitan  area, Rhode
Island,  Pennsylvania,  and now  Massachusetts  and New  Hampshire,  through the
following four lines of business:  (i) Home Energy Services provides residential
customers with service and maintenance of energy systems and appliances, as well
as the retail  marketing of natural gas and electricity to residential and small
commercial   customers;    (ii)   Business   Solutions   provides   professional
engineering-consulting   and  design  of  energy   systems  for  commercial  and
industrial customers,  including installation of plumbing, heating,  ventilation
and air conditioning equipment;  (iii) Commodity Procurement provides management
and  procurement  services  for fuel  supply  and  management  of energy  sales,
primarily for and from the  Ravenswood  facility;  and (iv) Fiber Optic Services
provides  various  services to carriers of voice and data  transmission  on Long
Island and in New York City.

Subsidiaries in the Energy Investments 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;  a 50%  interest  in the
Premier  Transco  Pipeline and a 24.5% interest in Phoenix  Natural Gas, both in
Northern  Ireland;  and investments in certain  midstream  natural gas assets in
Western  Canada  through  KeySpan  Canada,  formerly  Gulf  Midstream.  With the
exception of KeySpan  Canada,  these  subsidiaries  are primarily  accounted for
under the equity method.  Accordingly,  equity income from these  investments is
reflected  in other income and  (deductions)  in the  Consolidated  Statement of
Income.  In  October  2000,  we sold  our  interest  in  certain  oil  producing
properties in Alberta,  Canada.  Further,  also in October 2000, we acquired the
remaining  50%  interest in Gulf  Midstream,  making us the sole owner,  and for
financial reporting purposes, these operations are consolidated in our financial
statements.

The Other segment represents  primarily  unallocated  administrative and general
expenses,  interest income earned on temporary cash  investments,  and preferred
stock  dividends.  Further,  this  segment  includes  our marine  transportation
subsidiary,  Midland  Enterprises,  that  was  acquired  as part of the  Eastern
acquisition. We have been ordered by the SEC to sell this subsidiary by November
8, 2003 because its operations are not functionally  related to our core utility
operations.

The accounting  policies of the segments are the same as those  described in the
summary  of  significant   accounting  policies.  Our  reportable  segments  are
strategic  business units that are managed separately because of their different
operating and regulatory  environments.  As a result, among other things, of our
acquisitions  of  Eastern  and ENI (and the  "push-down"  of  goodwill  and debt
associated with the acquisitions on the individual  financial  statements of the
companies acquired),  we are currently reviewing the components of our strategic
business  units and the related  method of evaluating  their  performance by our
Chief Operating Officer and Board of Directors. Any changes in the components of
our business  segments and/or the nature of reporting  their  operating  results
from such current  review will be effective  with our reporting of first quarter
2001 results. The reportable segment information is as follows:

                                       54

<PAGE>



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

                               Gas        Electric    Gas Exploration  Energy     Energy
                          Distribution    Services    and Production   Services   Investments  Other      Eliminations  Consolidated
------------------------------------------------------------------------------------------------------------------------------------
<S>                         <C>          <C>            <C>          <C>        <C>            <C>         <C>            <C>
Year Ended December 31, 2000

Unaffiliated Revenue         2,555,785     1,444,711     274,209      771,861     33,507         41,417            -       5,121,490
Intersegment Revenue                 -             -           -       63,912          -              -     (63,912)               -
Depreciation, depletion
and amortization               143,335        49,278      95,364       10,511      6,422         30,196            -         335,106
Operating Income               359,399       238,891     134,410       77,805      1,055       (79,697)            -         731,863
Income from equity
  method subsidiaries                -             -           -            -     20,010              -            -          20,010
Interest income                  3,951         1,214           -          966      6,134         74,957     (74,032)          13,190
Interest charges               111,176        24,254      11,360          125      7,636        128,428     (79,629)         203,350
Earnings for Common Stock      160,178       121,997      58,211       40,946     13,929      (112,567)            -         282,694
Basic and Diluted
  Earnings Per Share     $        1.19   $      0.91  $     0.43    $    0.31   $   0.10   $     (0.84)   $        -       $    2.10

Total assets                 7,286,138     1,858,813     830,170      768,016    683,399      5,511,506    (5,387,921)    11,550,121
Investment in equity
  method subsidiaries               -             -            -       15,433    109,751          3,387             -        128,571
Construction expenditures      274,941        69,921     243,799       17,362     26,388            624             -        633,035
--------------------------------------  ------------  ------------ ------------ ----------  -------------- -------------  ----------
</TABLE>
Electric  Services  revenues  from  LIPA,  Consolidated  Edison and the New York
Independent System Operator of $1.4 billion for the year ended December 31, 2000
represents approximately 28% of our consolidated revenues during that period.

Eliminating  Items  include  intercompany  interest  income and  expense and the
elimination of certain intercompany accounts receivable.



























                                       55

<PAGE>


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

                                Gas         Electric   Gas Exploration   Energy      Energy
                            Distribution    Services   and Production    Services   Investments   Other   Eliminations  Consolidated
------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1999
<S>                           <C>         <C>           <C>           <C>          <C>         <C>          <C>           <C>
Unaffiliated Revenue           1,753,132     861,582      150,581      186,529        2,789            -             -     2,954,613
Depreciation, depletion and
  amortization                   102,997      44,334       74,051        3,548        1,308       27,202             -       253,440
Operating Income                 308,410     139,940       48,530       (4,643)      (6,784)      (3,284)            -       482,169
Income from equity
  method subsidiaries                  -           -            -            -       15,347            -             -        15,347
Interest income                    3,942           -            -            -        5,016       19,393        (1,358)       26,993
Interest charges                  88,370      22,380       13,307            -        3,726       95,252       (89,284)      133,751
Earnings for  Common Stock       151,217      77,099       15,772       (2,528)       8,543      (26,244)            -       223,859
Basic and Diluted
  Earnings Per Share         $      1.09  $     0.56   $     0.11    $   (0.02)   $    0.06     $  (0.18)    $       -    $     1.62

Total assets                   3,774,563   1,267,931      646,657      202,124      503,549     2,584,674   (2,248,807)    6,730,691
Investment in equity
  method subsidiaries                  -           -            -       13,393      341,874         4,016            -       359,283
Construction expenditures        213,845     245,177      183,322        6,179       10,028        13,294            -       671,845
----------------------------- ------------- --------   -----------   ----------   ----------  ------------  -----------     --------
</TABLE>
Electric  Services  revenues from LIPA, and Consolidated  Edison of $859 million
for the  year  ended  December  31,  1999  represents  approximately  29% of our
consolidated revenues during that period.

Eliminating  Items  include  intercompany  interest  income and  expense and the
elimination of certain intercompany accounts receivable.

































                                       56

<PAGE>

<TABLE>
<CAPTION>

                                                                                                       (In Thousands of Dollars)

                                  Gas         Electric   Gas Exploration   Energy     Energy
                              Distribution    Services    and Production   Services   Investments  Other  Eliminations  Consolidated
----------------------------- ------------------------------------------------------------------------------------------------------
Nine Months Ended December 31, 1998
<S>                           <C>           <C>          <C>             <C>        <C>        <C>          <C>          <C>
Unaffiliated Revenue             856,172      738,316       70,812         63,064        117             -           -     1,728,481
Depreciation, depletion and
  amortization                    57,351        5,895      177,114            256      1,117        13,126           -       254,859
Operating Income                  57,753      132,016        7,446         (5,914)    (3,890)     (106,678)          -       80,733*
Income from equity
  method subsidiaries                  -            -            -              -      5,841             -           -         5,841
Interest income                    1,328            -            -              -          -        49,200        (424)       50,104
Interest charges                  60,678       69,953        3,870              -          -        60,700     (54,468)      140,733
Earnings for
  Common Stock                     (142)       43,594        2,218         (3,212)    (4,186)      (71,799)          -    (33,527)**
Basic and Diluted
  Earnings Per Share     $            -   $      0.30   $     0.02   $     (0.02) $    (0.03)  $    (0.50)           -   $    (0.23)

Total assets                  3,452,361       693,162      500,162        116,771    429,157     4,439,307  (2,735,818)    6,895,102
Investment in equity
  method subsidiaries                 -             -            -              -    289,193             -           -       289,193
Construction expenditures       128,405        54,090      182,729         28,421    231,791        51,127           -       676,563
---------------------------  -----------  -----------  ------------- -------------- ----------  ----------- ------------  ----------
</TABLE>
*Excludes a charge of $130 million to write-down  Houston  Exploration's  proved
gas reserves.
**Excludes special charges  associated with the LIPA Transaction.  See Note 16 -
Costs Related to the LIPA Transaction and Special Charges.

Electric  Services  revenues from LIPA of $408 million for the nine months ended
December 31, 1998  represents  approximately  24% of our  consolidated  revenues
during that period.

Eliminating  Items  include  intercompany  interest  income and  expense and the
elimination of certain intercompany accounts receivable.


Note 3. Income Tax

For calendar year 1999, we began to file  consolidated  federal and state income
tax returns.  A tax sharing  agreement  between  ourselves and our  subsidiaries
provides for the  allocation  of a realized tax  liability or benefit based upon
separate return  contributions  of each subsidiary to the  consolidated  taxable
income or loss in the consolidated income tax returns.

Income tax expense in 1999  reflects an  adjustment  to deferred tax expense and
current tax expense for the  utilization  of  previously  deferred net operating
loss  carryforwards  recorded in 1998.  In 1998,  we recorded as a deferred  tax
asset,  a benefit of $71.1  million for net  operating  loss  carryforwards.  We
estimated  that  $57.4  million  of the  benefits  from the net  operating  loss
carryforwards  from 1998 would be realized in our consolidated  1999 federal and
state income tax returns and,  accordingly,  we applied the net  operating  loss
benefits in our 1999 federal and state tax provisions.


                                       57

<PAGE>




Income tax  expense  (benefit)  is  reflected  as  follows  in the  Consolidated
Statement of Income:
<TABLE>
<CAPTION>
                                                                                          (In Thousands of Dollars)
-------------------------------------------------------------------------------------------------------------------
                                                                                                     Nine Months
                                                   Year Ended                Year Ended                 Ended
                                                December 31, 2000         December 31, 1999       December 31, 1998
-------------------------------------------------------------------------------------------------------------------
<S>                                                 <C>                       <C>                      <C>
Current  income tax                           $      169,823    $               26,618  $                 26,142
Deferred  income tax                                  46,453                   109,744                  (85,936)
                                                     -------                   -------                 ---------
                                                     216,276                   136,362                  (59,794)
                                                     -------                   -------                 ---------
Current - transaction related (1)                          -                         -                  291,365
Deferred - transaction related (2)                         -                         -                 (391,066)
                                                     -------                   -------                 ---------
                                                           -                         -                  (99,701)
                                                     -------                   -------                 ---------
Total  income tax (benefit)                   $      216,276    $              136,362  $              (159,495)
----------------------------------------------------------------------------------------------------------------
</TABLE>
           (1)     Primarily represents income taxes associated with the sale of
                   assets (the "Transferred  Assets") to us by LIPA, which taxes
                   were paid by us, partially offset by tax benefits  recognized
                   upon funding of postretirement benefits.

           (2)     Primarily   represents  the  deferred  federal  income  taxes
                   necessary to account for the difference between the carryover
                   basis  of  the  assets  sold  to us for  financial  reporting
                   purposes and the new increased tax basis.

The  components  of  deferred  tax assets  and  (liabilities)  reflected  in the
Consolidated Balance Sheet are as follows:
<TABLE>
<CAPTION>
                                                                                       (In Thousands of Dollars)

                                                             December 31, 2000            December 31, 1999
------------------------------------------------------  ---------------------------- ----------------------------
<S>                                                            <C>                          <C>
Reserves not currently deductible                       $         56,559        $              35,569
Benefits of tax loss carryforwards                                26,276                       13,694
Property related differences                                    (503,030)                    (155,063)
Regulatory tax asset                                             (21,375)                     (22,912)
Property taxes                                                    (9,740)                     (49,172)
Other items - net                                                   (411)                     (11,046)
                                                                ---------                    ---------
Net deferred tax liability                              $       (451,721)       $            (188,930)
-----------------------------------------------------------------------------------------------------------------
</TABLE>










                                       58

<PAGE>





The following is a  reconciliation  between reported income tax and tax computed
at the federal income tax statutory rate of 35%:
<TABLE>
<CAPTION>
                                                                                             (In Thousands of Dollars)

                                                                                                                Nine Months
                                                               Year Ended             Year Ended                   Ended
                                                              December 31,           December 31,              December 31,
                                                                  2000                   1999                      1998
---------------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>                    <C>                         <C>
Computed at the statutory rate                           $     180,979          $      138,241                  $ (114,249)
Adjustments related to:
      Net benefit from LIPA Transaction (1)                          -                       -                     (31,503)
      Tax credits                                               (1,181)                 (2,154)                     (1,809)
      Minority interest in Houston
           Exploration                                           8,768                   3,105                     (10,220)
      State income tax                                          30,384                   4,635                           -
      Other items - net                                         (2,674)                 (7,465)                     (1,714)
                                                         --------------------   ----------------------   ------------------
Total income tax (benefit)                               $     216,276          $      136,362                  $ (159,495)
-------------------------------------------------------  --------------------   ----------------------   ------------------
Effective income tax rate (2)                                      42%                     35%                         N/A
</TABLE>
          (1) Includes tax benefits  relating to (a) the deferred federal income
          taxes  necessary to account for the  difference  between the carryover
          basis of the Transferred  Assets for financial  reporting purposes and
          the new  increased  tax basis and (b) certain  credits  for  financial
          reporting  purposes,  including tax benefits recognized on the funding
          of   postretirement   benefits,   partially  offset  by  income  taxes
          associated with the sale of the Transferred Assets to us by LIPA which
          taxes were paid by us.

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



























                                       59

<PAGE>





Note 4.  Postretirement Benefits

Pension Plans: The following information represents the consolidated results for
our noncontributory  defined benefit pension plans which cover substantially all
employees. Benefits are based on years of service and compensation.  Funding for
pensions is in  accordance  with  requirements  of federal law and  regulations.
Prior to the KeySpan  Acquisition,  pension benefits had been managed separately
by our regulated  subsidiaries,  which were the only  subsidiaries  with defined
benefit  plans.  We are  currently  integrating  our  plans and  allocations  to
individual  business segments.  KEDLI is subject to certain deferral  accounting
requirements  mandated by the NYPSC for pension  costs and other  postretirement
benefit costs.

The calculation of net periodic pension cost is as follows:

<TABLE>
<CAPTION>
                                                                                                 (In Thousands of Dollars)
----------------------------------------------------------------------------------------------------------------------------
                                                 Year Ended                 Year Ended               Nine Months Ended
                                              December 31, 2000          December 31, 1999           December 31, 1998
---------------------------------------  --------------------------- -------------------------  ----------------------------
<S>                                             <C>                      <C>                            <C>
Service cost, benefits earned
    during the period                    $        35,810            $       38,372             $          24,608
Interest cost on projected
     benefit  obligation                         109,907                   106,888                        66,341
Expected return on plan assets                  (167,612)                 (138,436)                      (78,201)
Special termination charge (1)                    45,838                         -                        61,558
Settlement Gain (2)                              (20,196)                        -                             -
Net amortization and deferral                    (54,881)                   (8,869)                       (7,486)
                                         --------------------------- -------------------------  ----------------------------
Total pension cost                       $       (51,134)           $       (2,045)             $         66,820
---------------------------------------  --------------------------- -------------------------  ----------------------------
</TABLE>

     (1) See  discussion  of early  retirement  program at end of note.
     (2) See  discussion  of pension  plan  settlement.  Pension  cost  includes
expense and income for KEDNE for the period  November 8, 2000  through  December
31, 2000.



                                       60

<PAGE>



The following  table sets forth the pension plans' funded status at December 31,
2000 and December 31, 1999. Plan assets are  principally  common stock and fixed
income securities.
<TABLE>
<CAPTION>
                                                                                        (In Thousands of Dollars)
-----------------------------------------------------------------------------------------------------------------
                                                              December 31, 2000             December 31, 1999
--------------------------------------------------------  -------------------------  ----------------------------
<S>                                                            <C>                             <C>
Change in benefit obligation:
   Benefit obligation at beginning of period              $     (1,529,815)   $                 (1,650,120)
   Benefit obligation of acquisitions                             (309,384)                        (11,700)
   Service cost                                                    (35,810)                        (38,372)
   Interest cost                                                  (109,907)                       (106,888)
   Amendments                                                      (34,400)                        (31,350)
   Actuarial gain (loss)                                          (115,402)                        205,798
   Special termination benefits                                    (45,838)                              -
   Settlements                                                     110,000                               -
   Benefits paid                                                    97,691                         102,817
                                                          ----------------------           ----------------------
Benefit obligation at end of period                             (1,972,865)                     (1,529,815)
                                                          ----------------------           ---------------------
Change in plan assets:
   Fair value of plan assets at beginning of period              2,048,325                       1,675,604
   Fair value of acquired plan assets                              301,998                               -
   Actual return on plan assets                                     69,489                         457,529
   Employer contribution                                            18,322                          18,009
   Settlements                                                    (110,410)                              -
   Benefits paid                                                   (97,691)                       (102,817)
                                                          ----------------------          ----------------------
Fair value of plan assets at end of period                       2,230,033                       2,048,325
                                                          ----------------------          ----------------------
   Funded status                                                   257,168                         518,510
   Unrecognized net (gain) from past experience
     different from that assumed and from
     changes in assumptions                                       (337,288)                       (667,652)
   Unrecognized prior service cost                                  79,914                          80,087
   Unrecognized transition obligation                                2,187                           3,163
Net prepaid (accrued) pension cost reflected              ----------------------          ----------------------
   on consolidated balance sheet                          $          1,981      $                  (65,892)
--------------------------------------------------------  ----------------------          ----------------------
</TABLE>

<TABLE>
<CAPTION>
                                                                                                              Nine Months
                                                          Year Ended                Year Ended                   Ended
                                                      December 31, 2000          December 31, 1999         December 31, 1998
-------------------------------------------------  ------------------------  ------------------------- -------------------------
Assumptions:
<S>                                                        <C>                        <C>                       <C>
   Obligation discount                                      7.00%                      7.50%                     6.50%
   Asset return                                             8.50%                      8.50%                     8.50%
   Average annual increase in compensation                  5.00%                      5.00%                     5.00%
-------------------------------------------------  ------------------------  ------------------------- -------------------------
</TABLE>

<PAGE>

Pension Plan Settlement

We have settled certain  participating  contracts covering retiree pension plans
with  MetLife.  As required  under SFAS No. 88, a gain of $20.2 million has been
recognized as part of our pension cost for the year ended December 31, 2000.

Other  Postretirement   Benefits:   The  following  information  represents  the
consolidated  results for our  noncontributory  defined  benefit plans  covering
certain health care and life insurance benefits for retired  employees.  We have
been funding a portion of future benefits over  employees'  active service lives
through   Voluntary   Employee   Beneficiary    Association   ("VEBA")   trusts.
Contributions  to  VEBA  trusts  are  tax  deductible,  subject  to  limitations
contained in the Internal Revenue Code. Prior to the KeySpan  Acquisition  other
postretirement   benefits  had  been  managed   separately   by  our   regulated
subsidiaries,  which were the only  subsidiaries  with defined benefit plans. We
are currently  integrating  our plans and  allocations  to  individual  business
segments.

Net  periodic   other   postretirement   benefit  cost  included  the  following
components:
<TABLE>
<CAPTION>
                                                                                                           (In Thousands of Dollars)
------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                     Nine Months
                                                              Year Ended                     Year Ended                 Ended
                                                           December 31, 2000              December 31, 1999        December 31, 1998
--------------------------------------------------- -------------------------------  --------------------------- -------------------
<S>                                                           <C>                          <C>                          <C>
Service cost, benefits earned
     during the period                              $           14,793                  $    16,747             $          9,569
Interest cost on accumulated post-
     retirement benefit obligation                              47,692                       42,616                       26,414
Expected return on plan assets                                 (42,890)                     (36,842)                     (23,267)
Special termination charge (1)                                   5,590                            -                        3,073
Net amortization and deferral                                   (9,291)                       3,429                       (5,255)
                                                    -------------------------------  --------------------------- -------------------
Other postretirement benefit cost                   $           15,894                  $    25,950             $         10,534
--------------------------------------------------- -------------------------------  --------------------------- -------------------
</TABLE>
(1)   See discussion of early retirement program at end of note.
Other  post-retirement  benefit costs  include  expense and income for KEDNE for
November 8, 2000 through December 31, 2000.



                                       61

<PAGE>



The following table sets forth the plan's funded status at December 31, 2000 and
December 31,  1999.  Plan assets are  principally  common stock and fixed income
securities.
<TABLE>
<CAPTION>
                                                                                           (In Thousands of Dollars)
--------------------------------------------------------------------------------------------------------------------
                                                                  December 31, 2000           December 31, 1999
------------------------------------------------------------  --------------------------  --------------------------
<S>                                                                    <C>                         <C>
Change in benefit obligation:
   Benefit obligation at beginning of period                  $         (602,053)       $           (728,255)
   Benefit obligation of acquisitions                                   (123,450)                     (3,075)
   Service cost                                                          (14,793)                    (16,747)
   Interest cost                                                         (47,692)                    (42,616)
   Plan participants' contributions                                         (678)                       (716)
   Amendments                                                                  -                       8,631
   Actuarial gain (loss)                                                (139,840)                    148,126
   Special termination benefits                                           (5,590)                          -
   Benefits paid                                                          38,579                      32,599
                                                              --------------------------  --------------------------
Benefit obligation at end of period                                     (895,517)                   (602,053)
                                                              --------------------------  --------------------------
Change in plan assets:
   Fair value of plan assets at beginning of period                      548,850                     478,778
   Fair value of acquired plan assets                                     39,263                           -
   Actual return on plan assets                                              816                      97,452
   Employer contribution                                                   3,838                       4,503
   Plan participants' contribution                                           678                         716
   Benefits paid                                                         (38,579)                    (32,599)
                                                              --------------------------  --------------------------
Fair value of plan assets at end of period                               554,866                     548,850
                                                              --------------------------  --------------------------
   Funded status                                                        (340,651)                    (53,203)
   Unrecognized net (gain) loss from past  experience
     different from that assumed and from changes in
     assumptions                                                         125,334                     (66,318)
   Unrecognized prior service cost                                        (8,924)                     (8,477)
Accrued benefit cost reflected on                             --------------------------  --------------------------
   consolidated balance sheet                                 $         (224,241)       $           (127,998)
------------------------------------------------------------  --------------------------  --------------------------
</TABLE>

<TABLE>
<CAPTION>
                                                      Year Ended                    Year Ended                  Nine Months Ended
                                                   December 31, 2000             December 31, 1999              December 31, 1998
--------------------------------------------------------------------------------------------------------- --------------------------
Assumptions:
<S>                                                    <C>                            <C>                            <C>
 Obligation discount                                    7.00%                          7.50%                          6.50%
 Asset return                                           8.50%                          8.50%                          8.50%
 Average annual increase in  compensation               5.00%                          5.00%                          5.00%
--------------------------------------------------------------------------------------------------------- --------------------------
</TABLE>


                                       62

<PAGE>



The measurement of plan  liabilities  also assumes a health care cost trend rate
of 8% grading  down to 6% in 2005.  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, 2000 by $99.8 million and the net periodic  health
care expense by $9.0  million.  A 1% decrease in the health care cost trend rate
would have the  effect of  decreasing  the  accumulated  postretirement  benefit
obligation as of December 31, 2000 by $87.4 million and the net periodic  health
care expense by $7.6 million.

In 1993,  LILCO adopted the provisions of SFAS No. 106,  "Employer's  Accounting
for  Postretirement  Benefits Other Than  Pensions," and recorded an accumulated
postretirement  benefit obligation and a corresponding  regulatory asset of $376
million. LIPA will reimburse us for costs related to postretirement  benefits of
the electric  business  unit  employees,  therefore,  we have  reclassified  the
regulatory asset for postretirement  benefits  associated with electric business
unit employees to a deferred asset.

In 1994, LILCO established VEBA trusts for union and non-union employees for the
funding of costs collected in rates for postretirement  benefits. For the fiscal
year ended March 31,  1998,  the trusts were funded with a  contribution  of $21
million. In May 1998, an additional $250 million was funded into the trusts.

Early Retirement Program

In  December  2000,  we  completed  an  early  retirement  program  for  certain
management  and union  employees.  The additional  obligations  for pensions and
other  postretirement  benefits are reflected at December 31, 2000.  Included in
the  pension  and  other  postretirement  benefits  expense  for the year  ended
December 31, 2000 are charges of $45.8  million and $5.6  million,  respectively
related to the early retirement program.

Note 5. Capital Stock

Common Stock:  Currently we have 450,000,000  shares of authorized common stock.
In 1998,  we  initiated  a program to  repurchase  a portion of our  outstanding
common  stock on the open  market.  At  December  31,  2000 we had 22.5  million
shares,  or  approximately  $650.7  million of Treasury  Stock  outstanding.  We
completed this repurchase plan in 1999 and now utilize Treasury Stock to satisfy
our common stock plans.  During 2000,  we issued 2.5 million  shares of Treasury
Stock  for the  dividend  reinvestment  feature  of our  Investor  Program,  the
Employee Stock Discount  Purchase Plan for Employees,  and the Employee  Savings
Plan.

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.


                                       63

<PAGE>



At December 31, 2000 we had 553,000 shares  outstanding of 7.07% Preferred Stock
Series B par value $100;  197,000 shares  outstanding of 7.17%  Preferred  Stock
Series C par value $100;  and 92,050 shares  outstanding  of 6% Preferred  Stock
Series A par value $100, in the aggregate totaling $84.2 million.

Boston Gas Company has 682,700 shares of 6.421%  non-voting  preferred stock par
value $25 per share  outstanding  at December 31, 2000.  This issue of preferred
stock has a 5% annual sinking fund requirement. We have the option of increasing
the sinking fund payment up to 10% per year. This issue is callable beginning in
2003  and  is  reflected  in  deferred  credits  and  other  liabilities  on the
Consolidated Balance Sheet.

On June 1, 2000, we redeemed, at maturity,  all 14,520,000 outstanding shares of
our 7.95% Preferred  Stock Series AA. Our obligation of $370.2 million  included
the mandatory  redemption  price of $25 per share  totaling  $363.0  million and
dividends payable totaling $7.2 million.

Note 6.  Nonqualified Stock Options

At December 31, 2000, we had stock-based  compensation  plans that are described
below.  Moreover,   under  a  separate  plan,  Houston  Exploration  has  issued
approximately  2.3 million stock options to key Houston  Exploration  employees.
KeySpan and Houston  Exploration  apply APB  Opinion 25,  "Accounting  for Stock
Issued to Employees," and related Interpretations in accounting for their plans.
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 No.  123,  "Accounting  for  Stock-Based
Compensation,"  our net income and earnings per share would have been  decreased
to the proforma amounts indicated below:

<TABLE>
<CAPTION>
                                                             Year Ended                   Year Ended               Nine Months Ended
                                                          December 31, 2000            December 31, 1999           December 31, 1998
------------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                     <C>                          <C>                        <C>
Income (loss) available for
   common stock (000):                As reported             $282,694                     $223,859                   ($195,537)
                                      Proforma                $276,167                     $215,416                   ($198,996)
Earnings (loss) per share:            As reported               $2.10                        $1.62                      ($1.34)
                                      Proforma                  $2.06                        $1.56                      ($1.37)
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

The weighted average fair value of grants issued in 2000 was $2.87. The weighted
average fair value of grants issued in 1999 was $3.65.  All grants are estimated
on the date of the grant  using the Black-  Scholes  option-pricing  model.  The
following  weighted average  assumptions were used for grants issued in 2000 and
1999  respectively:  dividend yield of 8.22% and 6.58%;  expected  volatility of
24.00% and 23.43%;  risk free  interest  rate of 6.54% and 5.72%;  and  expected
lives of 6 years.  The weighted  average exercise price is $22.69 and $27.58 for
the 2000 and 1999 grants, respectively. There were no grants issued in 1998.

                                       64

<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               Year Ended                    Nine Months Ended
                                                  December 31, 2000        December 31, 1999                December 31, 1998
-------------------------------------- ---------------------------- -------------------------------- -------------------------------
                                                      Weighted                        Weighted                          Weighted
Fixed Options                                         Average                          Average                          Average
                                           Shares  Exercise Price     Shares       Exercise Price        Shares      Exercise Price
-------------------------------------- ---------------------------- ------------ ------------------- -------------------------------
<S>                                   <C>             <C>             <C>             <C>              <C>              <C>
Outstanding at beginning of period      4,968,398      $28.18            921,066       $30.80           992,300          $30.70
Granted during the year                 3,165,822      $22.69          4,149,000       $27.58             --              --
Exercised                              (1,577,259)     $27.82             (2,666)      $27.75           (13,631)         $28.67
Forfeited                                (100,334)     $26.04            (99,002)      $27.22           (57,603)         $29.45
                                       ---------------------------- ------------ ------------------- -------------------------------
Outstanding at end of period            6,456,627      $25.61          4,968,398       $28.18           921,066          $30.80
-------------------------------------- ---------------------------- ------------ ------------------- -------------------------------
Exercisable at end of period            2,759,599      $29.57          3,638,448       $28.53           921,066          $30.80
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
   Options Outstanding         Remaining         Weighted Average        Options Exercisable
  at December 31, 2000     Contractual Life       Exercise Price        at December 31, 2000
---------------------------------------------- --------------------------------------------------
<S>    <C>                    <C>                    <C>                      <C>
         65,000                 5 years               $27.00                      65,000
         277,993                6 years               $30.29                     277,993
         338,410                7 years               $32.57                     338,410
        1,681,108               8 years               $27.86                   1,509,068
        1,089,935               9 years               $26.81                     561,058
        3,004,181              10 years               $22.72                       8,070
        ---------                                                              ---------
        6,456,627                                                              2,759,599
---------------------------------------------- --------------------------------------------------
</TABLE>

<PAGE>

Note 7. Long-Term Debt

Gas Facilities  Revenue Bonds:  KEDNY can issue tax-exempt bonds through the New
York State Energy Research and Development Authority.  Whenever bonds are issued
for  new  gas  facilities   projects,   proceeds  are  deposited  in  trust  and
subsequently withdrawn to finance qualified  expenditures.  There are no sinking
fund  requirements  on any of our Gas Facilities  Revenue Bonds. At December 31,
2000, KEDNY had $648.5 million of Gas Facilities Revenue Bonds outstanding.  The
interest  rate on the variable  rate series due December 1, 2020 is reset weekly
and ranged from 3.40% to 4.90%  through  December  31,  2000,  at which time the
average rate was 3.97%.

We have an interest rate swap  agreement in which  approximately  $70 million of
our Gas Facility Revenue Bonds, 6.75% Series A and B, were effectively exchanged
for floating rate debt. (See Note 10, "Hedging, Derivative Financial Instruments
and Fair Values.")

Authority  Financing  Notes: Our electric  generation  subsidiary can also issue
tax-exempt  bonds  through the New York State Energy  Research  and  Development
Authority. At December 31, 2000, $41.1 million of Authority Financing Notes 1999
Series A Pollution  Control Revenue Bonds due October 1, 2028 were  outstanding.
The  interest  rate on these notes is reset based on an auction  procedure.  The
interest rate during the year ranged from 3.40% to 5.25%,  through  December 31,
2000 at which time the rate was 4.00%.

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 2.80% to 5.85%  through  December  31, 2000 at
which time the average rate was 4.04%.

Promissory Notes: In accordance with the LIPA agreement, LIPA assumed all of the
outstanding  long- term debt of LILCO at May 28, 1998 except for the 1997 Series
A Electric  Facilities Revenue Bonds due December 1, 2027 which were assigned to
us. In accordance with the LIPA agreement,  we issued  promissory  notes to LIPA
which  represented an amount  equivalent to the sum of: (i) the principal amount
of 7.30% Series  Debentures  due July 15, 1999 and 8.20% Series  Debentures  due
March 15, 2023 outstanding at May 28, 1998, and (ii) an allocation of certain of
the Authority  Financing Notes. The promissory notes contain  identical terms as
the debt referred to in items (i) and (ii) above.  During 1999, we  extinguished
our obligation under certain  promissory notes to LIPA. Our obligation for these
promissory notes had a principal amount of $442.5 million.

Notes  Payable:  On  February  1, 2000,  KEDLI  issued  $400  million of 7.875 %
Medium-Term  Notes due February 1, 2010.  The net proceeds  from the issuance of
these  notes were used to  reimburse  our  treasury  for costs in  extinguishing
certain   promissory  notes  to  LIPA,  as  previously  noted.  (For  additional
information on this issuance see Note 11, "KeySpan Gas East Corporation  Summary
Financial Data.")




                                       65

<PAGE>



In November 2000, we issued $1.65 billion of Medium-Term Notes, the net proceeds
of which  were used to repay  commercial  paper  that was  issued  to  finance a
portion of the  acquisition  of Eastern and ENI.  The notes were issued in three
series as follows:  $700 million,  7.25% Notes due 2005;  $700  million,  7.625%
Notes due 2010 and $250 million, 8.00% Notes due 2030.

Additionally,  Boston Gas Company has  outstanding  $210 million of  Medium-Term
Notes. These notes,  which are not callable until maturity,  have interest rates
ranging from 6.80% - 9.75% and mature in 2005-2025.

At December 31, 2000, Houston Exploration had outstanding $100 million of 8.625%
Senior  Subordinated  Notes  due  2008.  These  notes  were  issued in a private
placement  in  March  1998  and are  subordinate  to  borrowings  under  Houston
Exploration's  line of  credit.  These  notes are  redeemable  at the  option of
Houston Exploration after January 1, 2003.

First Mortgage Bonds:  Eastern and ENI and their respective  subsidiaries,  have
issued and  outstanding  approximately  $323  million of first  mortgage  bonds.
Approximately  $180  million of these  bonds are  secured  by KEDNE gas  utility
property and $143 million are secured by marine  transportation  equipment.  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.

Commercial Paper and Revolving Credit  Agreements:  We have two revolving credit
agreements  with a  commercial  bank  syndicate  totaling  $1.4  billion.  These
agreements  expire in September 2001, and our current intention is to renew both
of these agreements.

Pricing under both facilities is subject to a ratings-based  grid with an annual
fee of .075% per annum on the balance of funds  available.  Borrowings will bear
interest at LIBOR plus 50 basis points. Borrowings in excess of more than 33% of
the total  commitment  will bear interest at LIBOR plus 62.5 basis  points.  The
credit facilities are used to support our $1.4 billion commercial paper program.
At December 31, 2000,  $1.3 billion of  commercial  paper was  outstanding  at a
weighted average annualized  interest rate of 7.01%; $99.7 million of commercial
paper was available for issuance.

Houston  Exploration has an unsecured available line of credit with a commercial
bank that provides for a maximum commitment of $250 million subject to borrowing
base  limitations.  This credit facility  supports  borrowings under a revolving
loan  agreement,  and at December 31, 2000, the borrowing base was $210 million.
Up to $2 million of this line is available for the issuance of letters of credit
to support performance guarantees. This credit facility matures on March 1, 2003
and is unsecured.  Houston Exploration  borrowed $32 million under this facility
during  2000,  and at  December  31,  2000,  borrowings  of  $145  million  were
outstanding  and $0.4 million was committed under  outstanding  letter of credit
obligations. Borrowings under this facility bear interest, at rates indexed at a
premium to the Federal Funds rate or LIBOR, or based on the prime rate depending
on amounts outstanding under the credit facility.  The weighted average interest
rate on this debt was 7.90% at December 31, 2000.



                                       66

<PAGE>



KeySpan  Canada has two  revolving  twelve month loan  agreements  with Canadian
banks. Under its agreement with the Bank of Canada,  KeySpan Canada borrowed $47
million US dollars in 2000. At December 31, 2000,  total  borrowings  under this
facility  were $133 million US dollars.  The weighted  average  interest rate on
these  borrowings at December 31, 2000 was 6.42%.  This credit facility has been
fully  utilized.  The second  facility was  negotiated  in 2000 with the Bank of
Montreal.  During the year,  KeySpan Canada borrowed $37 million US dollars at a
weighted  average  interest  rate of 6.46%.  KeySpan  Canada has $46  million US
dollars  available for future  borrowing under this facility.  These  borrowings
were used to acquire the remaining 50% interest in Gulf  Midstream as well as to
fund capital expenditures associated with our Canadian activities.

Capital Leases:  Our subsidiaries  lease certain  facilities and equipment under
long-term  leases  which  expire on various  dates  through  2020.  The weighted
average interest rate on these obligations was 7.68%.

Debt Maturity:  Debt repayment  requirements,  including  capitalized leases and
related maturities, are $5.4 million, $5.0 million, $11.1 million, $0.7 million,
and $13.5 million for the years 2001 through 2005, respectively and cumulatively
$4.3 billion thereafter.

Note 8.  New York Independent System Operator Matters

We currently  realize  revenues from our investment in the  Ravenswood  facility
through the wholesale sale of energy,  installed capacity and ancillary services
at FERC approved market based rates. Energy is a quantity of electricity that is
produced  over a  period  of time  and is  measured  in  megawatt  hours  (MWh).
Installed  capacity ("ICAP") is the capability to generate  electrical power and
is measured in megawatts (MW). Ancillary services include 10-minute spinning and
non-spinning reserves available to replace energy that is unable to be delivered
due to the  unexpected  loss of a major energy source.  The Ravenswood  facility
currently sells its energy,  installed  capacity and ancillary  services through
bidding  into the NYISO  energy  markets.  It also has the ability to sell these
services through bilateral transactions.

As a condition of FERC's approval of the Ravenswood facility's market based rate
authority, it is subject to certain mitigation measures associated with the sale
of its products, the most significant of which are the day ahead energy bid cap,
and installed capacity bid and price cap.

Currently,  the  Ravenswood  facility's  energy bids are  evaluated  against the
energy price at Indian Point 2 ("Indian  Point").  If the Ravenswood  facility's
bid prices  become five  percent  greater  than the price at Indian  Point,  the
Ravenswood  facility's  bid  price  is not  used.  Instead,  its  bid is  capped
(mitigated)  at  the  amount  that  the  Ravenswood   facility  has  bid  during
unmitigated hours in the prior 90 days. With respect to installed capacity,  the
Ravenswood  facility,  as a New York City supplier,  is currently  subject to an
$8.75 per kW-month ICAP bid and price cap.



                                       67

<PAGE>



Due to recent market activity and volatility in the New York energy markets,  as
well as the projected increased demand for energy during the summer of 2001, the
NYISO, NYPSC and FERC have proposed, evaluated and implemented additional market
mitigation  measures.  Many of these  mitigation  measures will remain in effect
during 2001 and additional  mitigation  measures are expected to be proposed and
possibly  implemented prior to the summer of 2001. These additional measures are
discussed below.

General Mitigation

On November 21, 2000, FERC granted NYISO's requested  extension of its Temporary
Extraordinary  Procedures  ("TEP")  authority  until April 30, 2001. The TEP are
designed  to  address   unanticipated   market  design  flaws  and  transitional
abnormalities  which occur  during the start-up  period of the NYISO.  Under the
TEP, the NYISO may take Extraordinary  Corrective Action in order to recalculate
energy prices, when possible with reasonable  certainty,  that are incorrect due
to market design flaws.  The NYISO will once again request that FERC extend this
TEP authority through October 31, 2002.

In addition, on March 1, 2001,  Consolidated Edison requested FERC to revise the
localized market power  mitigation  measures for generating units located in the
New York City service area.  Specifically,  Consolidated  Edison  requested that
existing bid mitigation  measures be applied to the real-time  market as well as
the  day  ahead  market.  Moreover,   Consolidated  Edison  requested  that  the
mitigation  measures apply to all existing and planned New York City  generation
and not only the divested Consolidated Edison generation.

The NYISO has also been developing a Circuit Breaker mechanism which,  according
to  the  NYISO,   is  intended  to  implement   existing   mitigation   measures
automatically  rather  than on a one day lag.  The  NYISO is in the  process  of
implementing  this  automatic  Circuit  Breaker.  It is not known if  regulatory
approvals  will be  obtained  nor the  potential  impact on revenues or earnings
associated with these measures.

Energy Mitigation

On July 26, 2000,  FERC approved a $1,000 per MWh energy price bid cap. The July
26,  2000  order  also  required  the NYISO to  identify  certain  "market  flaw
problems"  and to  report  them to FERC by  September  1,  2000.  (See  Reserves
Mitigation for further discussion). FERC has extended this cap through April 30,
2001,  and the NYISO will once again  request  FERC  extend  this $1,000 per MWh
energy bid cap through October 31, 2002.

Reserves Mitigation

Due to  volatility  in the  market-clearing  price  of  10-minute  spinning  and
non-spinning reserves during the first quarter of 2000, the NYISO requested that
FERC approve a bid cap on reserves as well as requiring a refunding of so-called
alleged  "excess  payments"  received  by sellers  into the  ancillary  services
market,  including the Ravenswood facility and LIPA. Other market  participants,


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<PAGE>


including  buyers of reserves  and electric  utilities as load serving  entities
also filed  complaints with FERC and intervened in the various FERC  proceedings
related to reserves, and proposed alternative remedies.

On May 31, 2000,  FERC issued an order on reserves  that  granted  approval of a
$2.52  per MWh  bid cap for 10  minute  non-spinning  reserves,  which  includes
payments for the opportunity cost of not making energy sales. FERC also required
the NYISO to submit  additional  information in a compliance  filing.  The other
requests,  such  as a  bid  cap  for  spinning  reserves,  retroactive  refunds,
recalculation  of reserve  prices for March  2000,  and  convening  a  technical
conference and settlement  proceeding , were  rejected.  However,  the NYISO and
several other market  participants have requested  rehearing of the May 31, 2000
order. In response to the NYISO rehearing request, FERC has allowed the NYISO to
recalculate  prices for  reserves  for the March  2000  period as if the bid cap
approved  effective  April 1, 2000 had been  effective  for March,  pending  its
review on the rehearing  requests of the May 31, 2000 order.  The final order on
the rehearing request is still pending.

On  November  8, 2000,  FERC  issued an order  extending  the $2.52 per MWh plus
opportunity  costs bid cap on  10-minute  non-spinning  reserves and the related
mandatory  bidding  requirement,  until  such time as FERC  determines  that the
non-spinning  reserve  markets are  demonstrated to be workably  competitive.  A
technical  conference  regarding  ancillary  services  was  conducted by FERC in
January  2001.  Market  participants  have provided  comments to FERC  including
opinions that the non-spinning  reserve markets are not workably competitive and
accordingly  the bid cap  should  continue.  We have  requested  this bid cap be
removed  because  additional  supply is now  available.  The proceeding is still
pending  and it is not known if or when the bid cap will be  removed or if other
market changes will be made.

Capacity Mitigation

The NYISO and market  participants have been discussing the  implementation of a
revised  ICAP market.  Currently,  a generator  may sell 100% of its  dependable
maximum net capacity.  The proposed  revision would reduce this amount by taking
into  account a generating  unit's  forced  outage rate.  At the same time it is
proposed to increase  the $8.75 per kW bid cap. The  magnitude of these  changes
have not been agreed to nor  approved by FERC and it is not known to what extent
these revisions will impact Ravenswood's revenues or earnings.

Note 9. Contractual Obligations and Contingencies

Lease Obligations:  Lease costs included in operation expense were $69.3 million
in 2000  reflecting,  primarily,  the Ravenswood  lease of $30.5 million and the
lease of our Brooklyn  headquarters  of $11.6 million.  Lease costs also include
leases  for other  buildings,  office  equipment,  vehicles  and power  operated
equipment.  Lease costs for the year ended December 31, 1999 were $47.1 million.
Lease costs for the nine months ended December 31, 1998 were $28.9 million.  The
future minimum lease payments under various  leases,  all of which are operating
leases,  are $68.7 million per year over the next five years and $253.4 million,
in the aggregate, for all years thereafter.


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<PAGE>



We acquired the 2,200 megawatt  Ravenswood facility located in Long Island City,
Queens,  New York, from  Consolidated  Edison on June 18, 1999 for approximately
$597 million. In order to reduce our cash requirements,  we entered into a lease
agreement with a special purpose,  unaffiliated financing entity that acquired a
portion of the facility directly from  Consolidated  Edison and leased it to our
subsidiary  under  a  ten  year  lease.  We  have  guaranteed  all  payment  and
performance  obligations of our subsidiary under the lease.  Another  subsidiary
provides all operating,  maintenance and construction services for the facility.
The lease relates to  approximately  $425 million of the acquisition cost of the
facility.  The lease  qualifies as an operating  lease for  financial  reporting
purposes  while  preserving  our ownership of the facility for federal and state
income tax  purposes.  The balance of the funds  needed to acquire the  facility
were provided from cash on hand.

Fixed Charges Under Firm Contracts:  Our utility  subsidiaries have entered into
various contracts for gas delivery,  storage and supply services.  The contracts
have  remaining  terms that cover from one to fourteen  years.  Certain of these
contracts  require  payment of annual demand charges in the aggregate  amount of
approximately $415 million.  We are liable for these payments  regardless of the
level of service we require  from third  parties.  Such  charges  are  currently
recovered from utility customers as gas costs.

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 or
financial condition.

In October 1998,  the County of Suffolk and the Towns of Huntington  and Babylon
commenced an action  against LIPA,  KeySpan,  the NYPSC and others in the United
States  District  Court for the Eastern  District  of New York (the  "Huntington
Lawsuit").  The  Huntington  Lawsuit  alleges,  among other  things,  that LILCO
ratepayers (i) have a property right to receive or share in the alleged  capital
gain that resulted from the  transaction  with LIPA (which gain is alleged to be
at least $1 billion);  and (ii) that LILCO was required to refund to  ratepayers
the amount of a  Shoreham-related  deferred tax reserve  (alleged to be at least
$800  million)  carried  on the books of LILCO at the  consummation  of the LIPA
Transaction.  In December 1998,  and again in June 1999, the plaintiffs  amended
their complaint.  The amended complaint contains allegations relating to certain
payments  LILCO  had  determined  were  payable  in  connection  with  the  LIPA
Transaction  and KeySpan  Acquisition  to LILCO's  Chairman  and certain  former
officers and adds the  recipients of the payments as  defendants.  In June 1999,
KeySpan was served with the second amended complaint.  On June 16, 2000, KeySpan
filed a motion to dismiss the second amended complaint.  On August 14, 2000, the
Court granted  KeySpan's  motion and dismissed the  plaintiffs'  second  amended
complaint in its entirety.  The plaintiffs have appealed that decision.  At this
time, we are unable to determine the outcome of this appeal.

A class settlement,  which became effective in June 1989 (County of Suffolk,  et
al., v. Long Island Lighting Company,  et al.), resolved a civil lawsuit against
LILCO brought under the federal Racketeer  Influenced and Corrupt  Organizations
Act, alleging that LILCO made inadequate disclosures before the NYPSC concerning
the construction and completion of nuclear generating facilities. The class

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<PAGE>



settlement provided electric customers with rate reductions of $390 million that
were being  reflected as  adjustments  to their monthly  electric bills over the
ten-year period June 1, 1990 through May 31, 2000.

In November 1999, class counsel for the LILCO ratepayers served a motion, in the
United States  District Court for the Eastern  District of New York,  seeking an
order directing KeySpan to pay $42 million, in addition to the amounts remaining
to be paid under the class settlement.  Class counsel contends that the required
rate  reductions  should have been  exclusive of gross receipts  taxes.  KeySpan
filed its  opposition in January 2000 and class counsel filed their reply papers
in February 2000. In their February  papers,  class counsel revised their demand
to seek an order  directing  KeySpan  to pay  approximately  $22  million,  plus
interest,  in  addition  to the  amounts  remaining  to be paid  under the class
settlement.  KeySpan filed its rebuttal  papers March 1, 2000 and oral arguments
were held  March 6,  2000.  On March 9,  2000,  an order was issued by the court
granting class counsel's motion.  On June 20, 2000,  KeySpan filed its appeal of
the District  Court's  order.  On December 7, 2000,  the United  States Court of
Appeals for the second circuit heard oral arguments on the matter. At this time,
we are unable to  determine  the  outcome  of this  appeal.  However,  we do not
believe  that  this  proceeding  will  have a  material  adverse  effect  on our
financial position, cash flows or results of operations.

Environmental Matters - New York/Long Island

We  have  identified  26  manufactured   gas  plant  ("MGP")  sites  which  were
historically   owned  or  operated  by  KEDNY  or  KEDLI  (or  such   companies'
predecessors).  Operations  at these  plants in the late 1800's and early 1900's
may have  resulted in the release of hazardous  substances.  These former sites,
some of which are no longer  owned by us, have been  identified  to both the New
York State  Department of  Environmental  Conservation  ("DEC") for inclusion on
appropriate waste site inventories and the NYPSC. The currently known conditions
of fourteen of these former MGP sites,  their period and magnitude of operation,
generally observed cleanup requirements and costs in the industry,  current land
use and  ownership,  and possible  reuse have been  considered  in  establishing
contingency reserves that are discussed below.

In 1995, Brooklyn Union executed an Administrative Order on Consent ("ACO") with
the DEC which  addressed the  investigation  and  remediation of a site in Coney
Island,  Brooklyn. In 1998, Brooklyn Union executed an ACO for the investigation
and  remediation  of the Clifton  MGP site in Staten  Island.  Further,  the DEC
notified  us in 1998 that the Sag Harbor and  Rockaway  Park MGP sites  owned by
KEDLI  would  require  remediation  under New York  State's  Superfund  program.
Accordingly,  the Sag Harbor and Rockaway Park sites;  as well as the Bay Shore,
Glen Cove,  Halesite and  Hempstead  MGP sites;  are the subject of two separate
ACOs,  which  we  executed  with  the DEC in  March  1999  and  September  1999,
respectively.   Field  investigations  and,  in  some  cases,  interim  remedial
measures,  are  underway or  scheduled to occur at each of these sites under the
supervision of the DEC and the New York State Department of Health.


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We were also requested by the DEC to perform preliminary site assessments at the
Patchogue,  Babylon, Far Rockaway,  Garden City and Hempstead MGP sites, each of
which  were  formerly  owned by LILCO,  under a  separate  ACO  entered  into in
September 1999. Initial studies based on existing  available  documentation have
been  completed  for each such site and the DEC has  requested  that we  collect
additional samples at each of the subject properties.

With the  exception  of the Coney  Island site,  which will be  redeveloped  for
commercial or industrial use, the final end uses for the sites  identified above
and, therefore,  acceptable  remediation goals have not yet been determined.  We
are required to prepare a  feasibility  study for the  remediation  of each such
site,  based on cleanup  levels derived from risk analyses  associated  with the
proposed  or  anticipated  future  use  of  the  properties.  The  schedule  for
completing  this  phase of the work  under  the  ACOs for the  identified  sites
discussed above extends through 2002.

Thus, thirteen sites identified above are currently the subject of ACOs with the
DEC and one is subject to the  negotiation  of such an agreement.  Our remaining
MGP sites may not  become  subject to ACOs in the  future,  and  accordingly  no
liability  has been  accrued for these sites.  It is  possible,  based on future
investigation,  that we may be required to undertake investigation and potential
remediation  efforts  at these,  or other  currently  unknown  former MGP sites.
However,  we are  currently  unable to determine  whether or to what extent such
additional costs may be incurred.

We believe that in the aggregate,  the accrued  liability for  investigation and
remediation of the MGP sites identified above are reasonable estimates of likely
cost within a range of reasonable,  foreseeable costs. Accordingly, we presently
estimate  the  remaining   cost  of  our  New  York/Long   Island  MGP-  related
environmental  cleanup activities will be $111.1 million;  which amount has been
accrued  by us as our  current  best  estimate  of our  aggregate  environmental
liability  for known sites.  As  previously  indicated,  the total New York/Long
Island MGP-related costs may be substantially higher, depending upon remediation
experience,  selected end use for each site, and actual environmental conditions
encountered.

The KEDNY rate plan  provides,  among  other  things,  that if the total cost of
investigation and remediation  varies from that which is specifically  estimated
for a site under  investigation  and/or  remediation,  then KEDNY will retain or
absorb up to 10% of the  variation.  The KEDLI rate plan also  provides  for the
recovery of investigation and remediation costs but with no consideration of the
difference  between estimated and actual costs.  Under prior rate orders,  KEDNY
has offset certain monies due to ratepayers against its estimated  environmental
cleanup  costs  for MGP  sites.  At  December  31,  2000,  we have  reflected  a
regulatory  asset of $88.8  million.  Expenditures  incurred  to date by us with
respect to MGP-related activities total $27.9 million.

In December  1996,  LILCO filed a complaint in the United States  District Court
for the Southern District of New York against fourteen insurance  companies that
issued general comprehensive liability policies to LILCO. In January 1998, LILCO
commenced a similar action against the same, and additional, insurance companies
in New York State Supreme Court,  and the federal court action  subsequently was
dismissed.  The state court action is being  conducted by us on behalf of KEDLI.


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<PAGE>


The outcome of this  proceeding  cannot yet be determined.  Periodic  settlement
discussions with these insurance carriers and third parties for reimbursement of
some  portion of MGP site  investigation  and  remediation  costs  continue.  In
addition, KEDNY is in discussions with insurance carriers regarding the possible
resolution  of  coverage  claims  related  to its  MGP  site  investigation  and
remediation  activities  without  litigation.  We are not  able to  predict  the
outcome of these discussions.

In addition,  we will be responsible for environmental  obligations  relating to
the  Ravenswood   facility   operations  other  than  liabilities  arising  from
pre-closing  disposal  of waste at off-site  locations  and any  monetary  fines
arising from Consolidated  Edison's  pre-closing  conduct.  Based on information
currently  available for environmental  contingencies  related to the Ravenswood
facility acquisition, we have accrued an additional $5 million liability.

We are awaiting final development of state and federal regulatory  programs with
respect  to NOx  reduction  requirements  for our  existing  power  plants.  Our
compliance  strategy may be composed of fuel choice  decisions,  acquisition  of
emission credits, and installation of emission control equipment.  The extent of
development  of new  generation  in the region will also  impact our  compliance
strategy. Although we are evaluating our alternatives, final decisions cannot be
made until pending  regulatory  requirements  and new  generation  decisions are
clarified.  Expenditures to address emission reduction  requirements through the
year 2004 are expected to be between $10 million and $15 million.

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

Environmental Matters - New England

We are aware of certain non-utility sites,  associated with former operations of
Eastern, for which we may have or share environmental remediation responsibility
or ongoing  maintenance,  the principal of which is a former coal tar processing
facility in Everett,  Massachusetts  (the "Facility").  The Facility,  which was
located on a 10-acre parcel of land formerly owned by Eastern, was operated by a
predecessor of Honeywell International, Inc. from the early 1900s until 1937 and
by a predecessor  of Beazer East,  Inc.  from 1937 until 1960,  when it was shut
down.  The  Facility  processed  coal  tar  purchased  from  Eastern's  adjacent
by-product  coke plant,  also shut down in 1960.  Eastern,  Beazer and Honeywell
have  entered into an ACO with the  Massachusetts  Department  of  Environmental
Protection  ("DEP") which requires that they jointly  investigate  and develop a
remedial response plan for the Facility, including any area where a release from
that site may have come to be located.  Such  companies have also entered into a
cost-sharing  agreement  under which each company has agreed to pay one-third of
the costs of compliance with the consent order,  while  preserving any claims it
may have against the other companies.  The companies have completed  preliminary
remedial measures,  including abatement of seepage of materials into an adjacent
tidal  river.  The Coast Guard has been  working with the DEP since July 1998 to
bring about a remedial solution that would abate the continuing sheening problem
in the river. Eastern, Beazer and Honeywell have proposed a remedial

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solution, a major element of which is the utilization of a containment structure
with limited dredging.  As of yet,  however,  no agreement has been reached with
the  regulators  as to the  appropriate  remedial  solution.  We  are  currently
recovering   certain  legal  defense  costs  and  may  be  entitled  to  recover
remediation costs (discussed below) from our insurers. In 1999 Eastern recovered
$2.5 million of prior defense costs from insurance carriers.

In addition,  Boston Gas Company, Colonial Gas Company and Essex Gas Company may
have  or  share  responsibility  under  applicable  environmental  laws  for the
remediation  of 28 MGP  sites.  A  subsidiary  of New  England  Electric  System
("NEES")  has assumed  responsibility  for  remediating  eleven of these  sites,
subject to a limited contribution from Boston Gas Company.

We are aware of 31 other former MGP sites within the New England utility service
territories. The NEES subsidiary has provided full indemnification to Boston Gas
Company with respect to eight of these sites. At this time, there is substantial
uncertainty as to whether Boston Gas Company,  Colonial Gas Company or Essex Gas
Company have or share  responsibility  for remediating any of these other sites.
No notice of  responsibility  has been  issued to us for any of these sites from
any governmental environmental authority.

 We  presently  estimate  the  remaining  cost  of  our  environmental   cleanup
activities  for the Facility and  MGP-related  sites will be  approximately  $20
million and $21.4 million,  respectively,  which amounts have been accrued by us
as our current best estimate of our aggregate  environmental liability for these
sites. We believe that in the aggregate, the accrued liability for investigating
and remediating the Facility and the New England MGP sites referred to above are
reasonable  estimates of likely cost within a range of  reasonable,  foreseeable
costs.  However,  the actual  remediation  cost for the Facility and MGP-related
sites may be substantially higher.

The DTE and New Hampshire  Public Service  Commission rate plans provide for the
recovery of site investigation and remediation  costs, and accordingly,  we have
reflected a regulatory asset of $27.8 million at December 31, 2000. Expenditures
incurred  for the period of November 8, 2000  through  December 31, 2000 totaled
$1.2 million.

Note 10.  Hedging, Derivative Financial Instruments, and Fair Values

Futures,  Options and Swaps: From time to time we utilize  derivative  financial
instruments,  such as  futures,  options  and swaps,  for the purpose of hedging
exposure to  commodity  price risk and to fix the selling  price on a portion of
our peak electric energy capacity.

Utility tariffs  applicable to certain  large-volume  customers permit gas to be
sold at prices  established  monthly  within a specified  range  expressed  as a
percentage of prevailing  alternate fuel oil prices.  We use gas swap contracts,
with offsetting positions in oil swap contracts of equivalent energy value, with
third  parties to fix profit  margins on specified  portions of gas sales to our
large-volume  market. The "long" gas position follows,  generally within a range
of 80% to 120%, the cost of gas to serve this

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<PAGE>



market while the offsetting oil swap position correspondingly replicates, within
the same range, the selling price of gas.

We have also engaged in the use of derivative  swap  instruments and gas futures
to fix the selling price on a portion of our estimated 2001 summer peak electric
energy  sales  from the  Ravenswood  facility  to  protect  against a  potential
degradation  in market prices and to fix the purchase  price on a portion of the
fuel used to generate electricity.  Under these swap agreements, we will receive
from a counter party a fixed price per megawatt hour of electricity  sold during
summer peak hours and pay the counter  party the then  current  floating  market
price for peak electric supply. We will receive the then current floating market
price of peak electric energy when the Ravenswood facility sells electric energy
to the NYISO.  These  derivatives are accounted for as cash-flow hedges. We also
have a  tolling  arrangement  with  two  counter  parties  under  which  we have
"locked-in"  a profit  margin on 117,600  megawatt  hours of 2001 summer  season
sales and 96,000 megawatt hours of 2001 winter sales. Under these  arrangements,
we will  receive  from  counter  parties  a fixed  margin  and will then pay the
counter  party,  on a monthly  basis,  our actual profit margin from the sale of
electric  energy.  As a result of these  hedging  arrangements,  we have  hedged
approximately  7% of our estimated 2001 yearly  electric sales. We have a stated
hedging  policy  that we will not hedge more than 50% of our daily  peak  sales.
Further,  as stated, we employ gas future contracts to fix the purchase price of
a portion of the gas used to fuel our Ravenswood  facility in  association  with
certain retail fixed fee electric sales.

Our gas and electric marketing subsidiary has a limited number of fixed rate gas
sales contracts for 2001 and utilizes standard NYMEX futures contracts and swaps
to fix profit  margins.  In the swap  instruments,  which are  employed to hedge
exposure to basis risk, we pay the amount by which the floating  variable  price
(settlement  price) is below the fixed price and receive the amount by which the
settlement  price exceeds the fixed price.  These  derivative  instruments  will
expire by August 2001.

Houston  Exploration  utilizes collars to hedge future sales prices on a portion
of its natural gas production to achieve a more  predictable  cash flow, as well
as to reduce its exposure to adverse price  fluctuations of natural gas. For any
particular collar  transaction,  the counter party is required to make a payment
to Houston  Exploration  if the settlement  price for any  settlement  period is
below the floor price for such transaction,  and Houston Exploration is required
to make payment to the counter party if the settlement  price for any settlement
period is above the ceiling price for such transaction. For any particular floor
transaction,  the  counter  party  is  required  to make a  payment  to  Houston
Exploration if the settlement price for any settlement period is below the floor
price for such  transaction.  Houston  Exploration  is not  required to make any
payment in connection with a floor transaction.  Houston  Exploration has hedged
approximately 70% of its estimated 2001 yearly production.








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<PAGE>


The following  tables set forth  selected  financial  data  associated  with our
derivative financial instruments that were outstanding at December 31, 2000.
<TABLE>
<CAPTION>

                         Year of      Volumes
 Type of Contract        Maturity       Mcf           Floor            Ceiling         Fixed Price      Current Price     Fair Value
----------------------- -------------------------  ----------------  ---------------  --------------  ----------------  ------------
<S>                       <C>         <C>         <C>              <C>                <C>              <C>                 <C>
          Gas                                            $                 $                 $                $               ($000)
Collars                    2001        58,400      3.63 - 4.00       5.30 - 6.37            -           5.33 - 9.98         (75,069)
Futures                    2001        13,360           -                 -            2.71 - 5.16      5.43 - 12.53          40,960
----------------------- ------------ ------------  --------------  ---------------  ----------------  ----------------- ------------
Total Gas                              71,760                                                                               (34,109)
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>

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

                                 Year of             Volumes
        Type of Contract         Maturity            Gallons              Fixed Price             Current Price         Fair Value
--------------------------- ------------------  ------------------  ------------------------  ---------------------  ---------------
<S>                               <C>               <C>                  <C>                     <C>                   <C>
          Oil                                                                  $                        $                 ($000)
Swaps                              2001              871,000              0.58 - 0.60              0.82 - 0.94          (10,936)
--------------------------- ------------------  ------------------  ------------------------  ---------------------  ---------------
</TABLE>

<TABLE>
<CAPTION>
                                Year of                       Fixed Margin /                             Estimated
     Type of Contract           Maturity        MWh               Price            Current Price           Margin         Fair Value
---------------------------  -------------- -------------  --------------------  ------------------  ------------------ ------------
<S>                              <C>          <C>           <C>                       <C>              <C>                 <C>
      Electricity                                                   $                    $                   $               ($000)
Tolling Arrangements              2001         213,600        25.00 - 62.00              -              9.72 - 91.54        (1,162)
Swaps                             2001         168,000       115.00 - 126.13           133.00                -              (2,209)
---------------------------  -------------- -------------  --------------------  ------------------  ------------------ ------------
Total Electricity                              381,600                                                                      (3,371)
---------------------------  -------------- -------------  --------------------  ------------------  ------------------ ------------
</TABLE>

As of December 31,  2000,  no futures  contract  extended  beyond  2001.  Margin
deposits  with brokers at December 31, 2000 of $0.6 million were recorded in the
current assets  section of the  Consolidated  Balance  Sheet.  Deferred gains on
closed positions were $6.1 million at December 31, 2000.

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  contracts  is no greater  than that
associated  with the primary  contracts which they hedge, as these contracts are
with major investment grade financial institutions,  and that elimination of the
price risk lowers overall business risk.

Interest  Rate Swaps:  We also have an  interest  rate swap  agreement  in which
approximately  $70 million of our Gas Facilities  Revenue Bonds,  6.75% Series A
and B, have been effectively exchanged for floating rate debt at The Bond Market
Association Swap Index. The interest rate swap agreement  expires in twenty-five
years,  but can be  terminated  earlier  based on certain  market  and  contract
conditions.  For the term of the  agreement,  we will  receive a fixed  interest


                                       76

<PAGE>



payment of 5.54%. The variable interest rate is reset on a weekly basis.  During
2000,  the average  variable  interest rate that we were obligated to pay ranged
from 2.93% to 5.84%.  Through  the  utilization  of this  interest  rate swap we
reduced our recorded interest expense by $1.3 million in 2000. The interest rate
swap  has a  negative  fair  value  to us of  $539,000  at  December  31,  2000,
reflecting the current interest rate we are required to pay to the counter party
and the fair value of certain embedded call option features.

Fair Values of Long-Term Debt
The fair values and carrying  amounts of our long-term debt at December 31, 2000
and December 31, 1999 were as follows:
<TABLE>
<CAPTION>

   Fair Value                                                  (In Thousands of Dollars)

                                          December 31, 2000               December 31, 1999
------------------------------------  -------------------------- ---  -------------------------
<S>                                            <C>                            <C>
First Mortgage Bonds                  $           330,057         $                    -
Notes                                           2,482,436                         96,000
Gas Facilities Revenue Bonds                      672,815                        632,409
Authority Financing Notes                          66,005                         66,005
Promissory Notes                                  598,769                        569,233
                                      -------------------             -------------------------
Total                                 $         4,150,082         $            1,363,647
------------------------------------  -------------------             -------------------------
</TABLE>
<TABLE>
<CAPTION>

   Carrying Amount                                              (In Thousands of Dollars)

                                       December 31, 2000                  December 31, 1999
-------------------------------------  -------------------------      --------------------------
<S>                                            <C>                            <C>
First Mortgage Bonds                   $          322,872         $                     -
Notes                                           2,360,000                         100,000
Gas Facilities Revenue Bonds                      648,500                         648,500
Authority Financing Notes                          66,005                          66,005
Promissory Notes                                  602,427                         602,427
                                       -------------------------      --------------------------
Total                                  $        3,999,804         $             1,416,932
-------------------------------------  -------------------------      --------------------------
</TABLE>

Other subsidiary debt is carried at an amount  approximating  fair value because
interest  rates  are  based  on  current  market  rates.   All  other  financial
instruments  included in the  Consolidated  Balance  Sheet are stated at amounts
that approximate fair values.
<PAGE>

Note 11. 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 us. 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 15, 2008. These notes are also guaranteed by us. The following condensed
financial  statements  are those of KEDLI and KeySpan as guarantor of the Medium
Term Notes.

<TABLE>
<CAPTION>
                                                                                                          (In Thousands of Dollars)
                                                                --------------------------------------------------------------------
             Balance Sheet                                                              December 31, 2000
                                                                --------------------------------------------------------------------

                                                                   Guarantor           KEDLI         Eliminations       Consolidated
                                                                ----------------   ---------------  ----------------   -------------
             ASSETS
            <S>                                                     <C>               <C>               <C>             <C>
             Current Assets
                Cash and temporary cash investments                    $ 94,508               $ -               $ -     $    94,508
                Accounts receivable, net                              2,002,412           277,632          (558,222)      1,721,822
                Other current assets                                    493,071            93,842                 -         586,913
                                                                ----------------   ---------------  ----------------   -------------
                                                                      2,589,991           371,474          (558,222)      2,403,243
                                                                ----------------   ---------------  ----------------   -------------
             Equity Investments                                         732,058                 -          (532,862)        199,196
                                                                ----------------   ---------------  ----------------   -------------
             Property
                Gas                                                   3,845,803         1,500,996                 -       5,346,799
                Other                                                 3,929,019                 -                 -       3,929,019
                Accumulated depreciation, depletion and
                    amortization                                     (2,649,261)         (268,260)                -      (2,917,521)
                                                                ----------------   ---------------  ----------------   -------------
                                                                      5,125,561         1,232,736                 -       6,358,297
                                                                ----------------   ---------------  ----------------   -------------

             Deferred Charges                                         2,382,258           207,127                 -       2,589,385
                                                                ----------------   ---------------  ----------------   -------------

             Total Assets                                          $ 10,829,868       $ 1,811,337      $ (1,091,084)   $ 11,550,121
                                                                ================   ===============  ================   =============


             LIABILITIES AND CAPITALIZATION
             Current Liabilities
                Accounts payable and accrued expenses               $ 1,232,730         $ 196,537               $ -     $ 1,429,267
                Notes payable                                         1,300,237                 -                 -       1,300,237
                Other current liabilities                               224,162            20,407                 -         244,569
                                                                ----------------   ---------------  ----------------   -------------
                                                                      2,757,129           216,944                 -       2,974,073
                                                                ----------------   ---------------  ----------------   -------------
             Intercompany Accounts payable, long-term                         -           382,318          (382,318)              -
                                                                ----------------   ---------------  ----------------   -------------

             Deferred Credits and Other Liabilities
                Deferred income tax                                     477,815           (26,094)                -         451,721
                Other deferred credits and liabilities                  711,931           112,239                 -         824,170
                                                                ----------------   ---------------  ----------------   -------------
                                                                      1,189,746            86,145                 -       1,275,891
                                                                ----------------   ---------------  ----------------   -------------

             Capitalization
                Common shareholders' equity                           2,798,652           550,026          (532,862)      2,815,816
                Preferred stock                                          84,205                 -                 -          84,205
                Long-term debt                                        3,874,938           575,904          (175,904)      4,274,938
                                                                ----------------   ---------------  ----------------   -------------
             Total Capitalization                                     6,757,795         1,125,930          (708,766)      7,174,959
                                                                ----------------   ---------------  ----------------   -------------
             Minority Interest in Subsidiary Companies                  125,198                 -                 -         125,198
                                                                ----------------   ---------------  ----------------   -------------
             Total Liabilities and Capitalization                  $ 10,829,868       $ 1,811,337      $ (1,091,084)   $ 11,550,121
                                                                ================   ===============  ================   =============
</TABLE>

<PAGE>

<TABLE>
<CAPTION>
                                                                                              (In Thousands of Dollars)
                                                  ---------------------------------------------------------------------
Balance Sheet                                                                December 31, 1999
                                                  ---------------------------------------------------------------------
                                                     Guarantor           KEDLI          Eliminations     Consolidated
                                                  ----------------   --------------   ---------------------------------
ASSETS
<S>                                                    <C>             <C>                 <C>              <C>
Current Assets
   Cash and temporary cash investments               $    128,602              $ -               $ -       $   128,602
   Accounts receivable, net                             1,236,171          278,722          (874,388)          640,505
   Other current assets                                   309,153           79,693                 -           388,846
                                                  ----------------   --------------   ---------------   ---------------
                                                        1,673,926          358,415          (874,388)        1,157,953
                                                  ----------------   --------------   ---------------   ---------------
Equity Investments                                      1,049,593                -          (657,862)          391,731
                                                  ----------------   --------------   ---------------   ---------------

Property
   Gas                                                  2,055,851        1,393,533                 -         3,449,384
   Other                                                2,900,424                -                 -         2,900,424
   Accumulated depreciation, depletion and
       amortization                                    (1,863,840)        (245,956)                -        (2,109,796)
                                                  ----------------   --------------   ---------------   ---------------
                                                        3,092,435        1,147,577                 -         4,240,012
                                                  ----------------   --------------   ---------------   ---------------
Deferred Charges                                          760,880          180,115                 -           940,995
                                                  ----------------   --------------   ---------------   ---------------
Total Assets                                          $ 6,576,834      $ 1,686,107      $ (1,532,250)       $6,730,691
                                                  ================   ==============   ===============   ===============
</TABLE>
<TABLE>
<CAPTION>
                                                     Guarantor           KEDLI           Eliminations    Consolidated
                                                  ----------------   --------------   ---------------   ---------------

LIABILITIES AND CAPITALIZATION
<S>                                                    <C>              <C>              <C>               <C>
Current Liabilities
   Accounts payable and accrued expenses                $ 502,866        $ 142,481               $ -         $ 645,347
   Notes payable                                          208,300                -                 -           208,300
   Other current liabilities                              525,755          405,850          (397,000)          534,605
                                                  ----------------   --------------   ---------------   ---------------
                                                        1,236,921          548,331          (397,000)        1,388,252
                                                  ----------------   --------------   ---------------   ---------------
Intercompany Accounts payable, long-term                   43,405          258,079          (301,484)                -
                                                  ----------------   --------------   ---------------   ---------------

Deferred Credits and Other Liabilities
   Deferred income tax                                    240,995          (52,065)                -           188,930
   Other deferred credits and liabilities                 491,637          102,784                 -           594,421
                                                  ----------------   --------------   ---------------   ---------------
                                                          732,632           50,719                 -           783,351
                                                  ----------------   --------------   ---------------   ---------------
Capitalization
   Common shareholders' equity                          2,717,113          653,074          (657,862)        2,712,325
   Preferred stock                                         84,339                -                 -            84,339
   Long-term debt                                       1,682,702          175,904          (175,904)        1,682,702
                                                  ----------------   --------------   ---------------   ---------------

Total Capitalization                                    4,484,154          828,978          (833,766)        4,479,366
                                                  ----------------   --------------   ---------------   ---------------
Minority Interest in Subsidiary Companies                  79,722                -                 -            79,722
                                                  ----------------   --------------   ---------------   ---------------

Total Liabilities and Capitalization                  $ 6,576,834      $ 1,686,107      $ (1,532,250)       $6,730,691
                                                  ================   ==============   ===============   ===============
</TABLE>
<PAGE>

<TABLE>
<CAPTION>
                                                   --------------------------------------------------------
Statement of Cash Flows                                       Year Ended December 31, 2000
                                                   --------------------------------------------------------
                                                       Guarantor             KEDLI        Consolidated
                                                   ------------------    --------------   -----------------
<S>                                                   <C>                 <C>               <C>
Operating Activities
Net Cash Provided by
      Operating Activities                      $         337,167     $     112,738    $        449,905
                                                   ---------------    --------------   -----------------

Investing Activities
  Capital expenditures                                   (518,058)         (114,977)           (633,035)
  Other                                                (2,238,775)                -          (2,238,775)
                                                   ---------------    --------------   -----------------
Net Cash (Used in) Provided by
      Investing Activities                             (2,756,833)         (114,977)         (2,871,810)
                                                   ---------------    --------------   -----------------

Financing Activities
  Treasury stock issued                                    72,289                 -              72,289
  Receipt/payment of dividends                            125,000          (125,000)                  -
  Redemption of preferred stock                          (363,000)                -            (363,000)
  Issuance of notes payable                             1,300,237                 -           1,300,237
  Issuance of long-term debt                            1,766,955           400,000           2,166,955
  Payment of long-term debt                               (68,365)                -             (68,365)
  Payment of notes payable                               (364,865)                -            (364,865)
  Long-term debt received (paid)                          397,000          (397,000)                  -
  Preferred stock dividends paid                          (20,261)                -             (20,261)
  Common stock dividends paid                            (239,740)                -            (239,740)
  Settlement of rate lock                                 (59,490)                -             (59,490)
  Net Intercompany accounts payable                      (124,239)          124,239                   -
  Other                                                   (35,949)                -             (35,949)
                                                   ---------------    --------------   -----------------
Net Cash Provided by
       Financing Activities                             2,385,572             2,239           2,387,811
                                                   ---------------    --------------   -----------------
Net (Decrease) Increase in
       Cash and Cash Equivalents                $         (34,094)    $           -     $       (34,094)
                                                   ===============    ==============   =================
Cash and cash equivalents
       at beginning of period                   $         128,602     $           -     $       128,602
Net (Decrease) Increase in
       Cash and Cash Equivalents                $         (34,094)    $           -     $       (34,094)
Cash and cash equivalents
       at End of Period                            ---------------    --------------   -----------------
                                                $          94,508     $           -     $        94,508
                                                   ===============    ==============   =================
</TABLE>

<PAGE>
<TABLE>
<CAPTION>
                                                   ----------------------------------------------------------
Statement of Cash Flows                                      Year Ended  December 31, 1999
                                                   ----------------------------------------------------------
                                                     Guarantor             KEDLI          Consolidated
                                                   ----------------------------------------------------------
<S>                                                     <C>                <C>                     <C>
Operating Activities
Net Cash Provided by
      Operating Activities                     $          564,109      $      24,896      $          589,005
                                                   ---------------     --------------     -------------------

Investing Activities
  Capital expenditures                                   (569,838)          (102,007)               (671,845)
  Other                                                   (23,819)                 -                 (23,819)
                                                   ---------------     --------------     -------------------
Net Cash (Used in) Provided by
      Investing Activities                               (593,657)          (102,007)               (695,664)
                                                   ---------------     --------------     -------------------

Financing Activities
  Treasury stock issued / (purchased)                    (299,243)                 -                (299,243)
  Issuance of notes payable                               208,300                  -                 208,300
  Issuance of long-term debt                              102,648                  -                 102,648
  Payment of long-term debt                              (442,475)                 -                (442,475)
  Preferred stock dividends paid                          (34,760)                 -                 (34,760)
  Common stock dividends paid                            (249,567)                 -                (249,567)
  Net Intercompany accounts payable                       (77,111)            77,111                       -
  Other                                                     7,582                  -                   7,582
                                                   ---------------     --------------     -------------------
Net Cash Provided by (Used in )
       Financing Activities                              (784,626)            77,111                (707,515)
                                                   ---------------     --------------     -------------------

Net (Decrease) Increase in
       Cash and Cash Equivalents               $         (814,174)     $           -      $         (814,174)
                                                   ===============     ==============     ===================

Cash and cash equivalents
       at beginning of period                  $          942,776      $           -      $          942,776
Net (Decrease) Increase in
       Cash and Cash Equivalents               $         (814,174)     $           -      $         (814,174)
Cash and cash equivalents
       at End of Period                            ---------------     --------------     -------------------
                                               $          128,602      $           -      $          128,602
                                                   ===============     ==============     ===================
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                    -----------------------------------------------------------
Statement of Cash Flows                                   Nine Months Ended  December 31, 1999
                                                    -----------------------------------------------------------
                                                      Guarantor             KEDLI          Consolidated
                                                    ---------------     ---------------    --------------------
<S>                                                    <C>                    <C>                   <C>
Operating Activities
Net Cash Provided by (Used in )
      Operating Activities                          $     (401,797)     $      (58,491)     $         (460,288)
                                                    ---------------     ---------------    --------------------

Investing Activities
  Capital expenditures                                    (616,880)            (59,683)               (676,563)
   Net proceeds from LIPA Transaction                    2,314,588                   -               2,314,588
  Other                                                    148,014              30,620                 178,634
                                                    ---------------     ---------------    --------------------
Net Cash (Used in) Provided by
      Investing Activities                               1,845,722             (29,063)              1,816,659
                                                    ---------------     ---------------    --------------------

Financing Activities
  Treasury stock issued / (purchased)                     (423,716)                  -                (423,716)
  Issuance of long-term debt                               112,535                   -                 112,535
  Issuance of preferred stock                               84,973                   -                  84,973
  Payment of long-term debt                               (103,000)                  -                (103,000)
  Preferred stock dividends paid                           (27,548)             (1,056)                (28,604)
  Common stock dividends paid                             (210,177)                  -                (210,177)
  Net Intercompany accounts payable                        (86,885)             86,885                       -
  Other                                                    (26,525)                  -                 (26,525)
                                                    ---------------     ---------------    --------------------
Net Cash Provided by (Used in )
       Financing Activities                               (680,343)             85,829                (594,514)
                                                    ---------------     ---------------    --------------------
Net (Decrease) Increase in
       Cash and Cash Equivalents                    $      763,582      $       (1,725)     $          761,857
                                                    ===============     ===============    ====================
Cash and cash equivalents
       at beginning of period                       $      179,194      $        1,725      $          180,919
Net (Decrease) Increase in
       Cash and Cash Equivalents                    $      763,582      $       (1,725)     $          761,857
Cash and cash equivalents
       at End of Period                             ---------------     ---------------    --------------------
                                                    $       942,776     $            -      $          942,776
                                                    ===============     ===============    ====================
</TABLE>

<TABLE>
<CAPTION>
                                                                                                         (In Thousands of Dollars)
                                        --------------------------------------------------------------------------------------------
Income Statement                                        Year Ended Ended December 31, 2000
                                        --------------------------------------------------------------------------------------------
                                                  Guarantor               KEDLI            Eliminations            Consolidated
                                             ---------------------    --------------     ------------------     --------------------
<S>                                                    <C>                <C>                     <C>                   <C>
 Revenues                                $              4,326,525     $     794,965      $               -      $         5,121,490
                                             ---------------------    --------------     ------------------     --------------------

 Operating Expenses
 Purchased gas                                          1,000,534           408,087                      -                1,408,621
 Fuel and purchased power                                 460,900                 -                      -                  460,900
 Operations and maintenance                             1,632,902           127,780                      -                1,760,682
 Intercompany expense net                                 (10,718)           10,718                      -                        -
 Depreciation and amortizations                           289,089            46,017                      -                  335,106
 Operating taxes                                          331,634            92,684                      -                  424,318
                                             ---------------------    --------------     ------------------     --------------------
 Total Operating Expenses                               3,704,341           685,286                      -                4,389,627
                                             ---------------------    --------------     ------------------     --------------------

 Operating Income                                         622,184           109,679                      -                  731,863

 Other Income and (Deductions)                             14,044              (707)               (24,767)                 (11,430)
                                             ---------------------    --------------     ------------------     --------------------

 Income (Loss) Before Interest
    Charges and Income Taxes                              636,228           108,972                (24,767)                 720,433

 Interest Expense                                         174,461            53,656                (24,767)                 203,350
 Income Taxes                                             197,914            18,362                      -                  216,276
                                             ---------------------    --------------     ------------------     --------------------
 Net Income                                               263,853            36,954                      -                  300,807

 Preferred Stock Dividends                                 18,113                 -                      -                   18,113

                                             ---------------------    --------------     ------------------     --------------------
 Earnings  for Common Stock              $                245,740     $      36,954      $               -      $           282,694
                                             =====================    ==============     ==================     ====================
</TABLE>

<PAGE>
<TABLE>
<CAPTION>

                                                                                                     (In Thousands of Dollars)
                                         -------------------------------------------------------------------------------------
Income Statement                                      Year Ended Ended December 31, 1999
                                         -------------------------------------------------------------------------------------
                                                Guarantor            KEDLI            Eliminations           Consolidated
                                             -----------------   ---------------   --------------------   --------------------
<S>                                               <C>                 <C>                     <C>                 <C>
 Revenues                                 $         2,317,525    $      637,088    $                 -    $         2,954,613
                                             -----------------   ---------------   --------------------   --------------------

 Operating Expenses
 Purchased gas                                        459,508           284,924                      -                744,432
 Fuel and purchased power                              17,252                 -                      -                 17,252
 Operations and maintenance                           981,331           109,835                      -              1,091,166
 Intercompany expense net                             (10,793)           10,793                      -                      -
 Depreciation and amortizations                       220,639            32,801                      -                253,440
 Operating taxes                                      282,521            83,633                      -                366,154
                                             -----------------   ---------------   --------------------   --------------------
 Total Operating Expenses                           1,950,458           521,986                      -              2,472,444
                                             -----------------   ---------------   --------------------   --------------------

 Operating Income                                     367,067           115,102                      -                482,169

 Other Income and (Deductions)                         96,884               159                (50,488)                46,555
                                             -----------------   ---------------   --------------------   --------------------

 Income (Loss) Before Interest
    Charges and Income Taxes                          463,951           115,261                (50,488)               528,724

 Interest Expense                                     133,751            50,488                (50,488)               133,751
 Income Taxes                                         113,106            23,256                                       136,362
                                             -----------------   ---------------   --------------------   --------------------
 Net Income                                           217,094            41,517                      -                258,611

 Preferred Stock Dividends                             34,752                 -                      -                 34,752

                                             -----------------   ---------------   --------------------   --------------------
 Earnings  for Common Stock               $           182,342    $       41,517    $                 -    $           223,859
                                             =================   ===============   ====================   ====================
</TABLE>

<PAGE>
<TABLE>
<CAPTION>
                                                                                                   (In Thousands of Dollars)
                                             -------------------------------------------------------------------------------
 Income Statement                                       Nine Months Ended December 31, 1998
                                             -------------------------------------------------------------------------------
                                                    Guarantor            KEDLI           Eliminations        Consolidated
                                                  --------------    ---------------    ----------------    -----------------
<S>                                                 <C>                  <C>                  <C>               <C>
 Revenues                                     $       1,371,847     $      356,634     $             -     $      1,728,481
                                                  --------------    ---------------    ----------------    -----------------

 Operating Expenses
 Purchased gas                                          181,068            150,622                   -              331,690
 Operations & maintenance expenses                      740,453            101,860                   -              842,313
 Intercompany expense, net                               (7,221)             7,221                   -                    -
 Depreciation and amortizations                         236,599             18,260                   -              254,859
 Operating taxes                                        203,307             53,817                   -              257,124
 Fuel and purchased power                                91,762                  -                   -               91,762
                                                  --------------    ---------------    ----------------    -----------------
 Total Operating Expenses                             1,445,968            331,780                   -            1,777,748
                                                  --------------    ---------------    ----------------    -----------------

 Operating Income                                       (74,121)            24,854                   -              (49,267)

 Other Income and (Deductions)                            6,387             (2,056)            (41,058)             (36,727)
                                                  --------------    ---------------    ----------------    -----------------

 Income (Loss) Before Interest
    Charges and Income Taxes                            (67,734)            22,798             (41,058)             (85,994)

 Interest Expense                                       140,733             41,058             (41,058)             140,733
 Income Taxes                                           (53,425)            (6,369)                  -              (59,794)
                                                  --------------    ---------------    ----------------    -----------------
 Net Income                                            (155,042)           (11,891)                  -             (166,933)

 Preferred Stock Dividends                               27,548              1,056                   -               28,604

                                                  --------------    ---------------    ----------------    -----------------
 Earnings (Loss) for Common Stock             $        (182,590)    $      (12,947)    $             -     $       (195,537)
                                                  ==============    ===============    ================    =================
</TABLE>


Note 12. Eastern/EnergyNorth Acquisition

On November 8, 2000,  we purchased all of the  outstanding  stock of Eastern for
$64.56  per  share in cash and all of the  outstanding  common  stock of ENI for
$61.46 per share in cash.  The  increased  size of KeySpan  should  enable us to
provide  enhanced  cost-effective  customer  service  and to  capitalize  on the
above-average  growth opportunities for natural gas in the Northeast and provide
additional  resources to our  unregulated  businesses.  We expect annual pre-tax
cost savings of  approximately  $40 million,  resulting from the  elimination of
duplicate corporate administrative programs and operating efficiencies.

The transactions have been accounted for using the purchase method of accounting
for business combinations. Accordingly, the accompanying consolidated statements
of income  include  Eastern and ENI  results  commencing  November 8, 2000.  The
purchase  price was allocated to the net assets  acquired  based upon their fair
value.  The historical cost basis of Eastern's and ENI's assets and liabilities,
with minor  exceptions,  was  determined  to represent the fair value due to the
existence  of  regulatory-approved   rate  plans  based  upon  the  recovery  of
historical  costs and a fair return  thereon.  The excess of the purchase  price
over the fair value of the net assets  acquired,  or goodwill,  of approximately
$1.5 billion has been recorded as an asset and is being  amortized over a period
of 20 to 40 years.

The  following  is  the  comparative   unaudited  proforma  condensed  financial
information  for the  years  ended  December  31,  2000 and 1999.  The  proforma
disclosures  reflect the results of the  operations of Eastern and ENI as if our
acquisitions were consummated on the first day of the reporting periods.


                                 Year Ended                       Year Ended
                             December 31, 2000                December 31, 1999
-----------------------  --------------------------  ---- ----------------------
                             (In Thousands of Dollars, Except Per Share Amounts)

Revenues                             6,130,158                        4,058,178
Operating Income                       671,081                          568,754
Net Income                             114,393                          174,923
Earnings Per Share                       $0.71                            $1.01
-------------------------------------------------------------------------------



                                       78

<PAGE>



Included  in the 2000  proforma  earnings,  are  merger  related  costs of $76.0
million,  after-tax,  recorded  by  Eastern  and  ENI  in  connection  with  our
acquisition of these  companies.  Excluding these costs,  proforma  earnings per
share for the year ended December 31, 2000 were $1.27.  These  proforma  results
may not be indicative of future  results.  Further,  the  consolidated  proforma
results  for 2000 and 1999 do not take into  account:  (i)  continued  gas sales
growth throughout our service territories,  especially on Long Island and in New
England;  (ii) earnings  enhancement  from our gas  exploration  and  production
operations;  (iii) the continued  successful  integration of acquired  companies
providing  energy-related  services within our Energy Services segment; and (iv)
anticipated  before- tax synergy  savings of $40  million  annually  starting in
2001.

Note 13.   Workforce Reduction Programs

As a result of the Eastern and ENI  acquisitions,  we have  implemented an early
retirement program and a severance program in an effort to reduce our workforce.
The early  retirement  program was  completed in December 2000 and resulted in a
workforce reduction of over 200 employees. We recorded a charge of $51.4 million
in  December  2000 to reflect  the  termination  benefits  for pension and other
postretirement  benefits related to the employees who voluntarily  elected early
retirement.

In addition,  in December 2000, we recorded a $15.0 million liability associated
with a severance program.  Eastern and ENI had previously recorded an additional
liability of $7.7 million associated with this severance program. This severance
program is targeted to reduce our workforce by an additional 500 employees.  The
plan  provides a severance  allowance  for certain  targeted  employees and will
continue through 2002.

Note 14.  Shareholder Rights Plan

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

Note 15. Sale of LILCO Assets,  Acquisition  of KeySpan Energy  Corporation  and
Transfer of Assets and Liabilities to KeySpan.

On May 28, 1998, LIPA acquired all of the outstanding  common stock of LILCO for
$2.4975  billion in cash and thereafter  directly or indirectly  assumed certain
liabilities ("LIPA Transaction"). Moreover, all of LILCO's outstanding long-term
debt as of May 28,  1998,  except  for its  1997  Series A  Electric  Facilities
Revenue Bonds due December 1, 2027 which were  assigned to KeySpan  Corporation,
was assumed by LIPA. In accordance with the LIPA Transaction, we issued

                                       79

<PAGE>



promissory notes to LIPA amounting to $1.048 billion which represented an amount
equivalent to the sum of (i) the principal amount of 7.30% Series Debentures due
July 15, 1999 and 8.20% Series  Debentures due March 15, 2023  outstanding as of
May 28,  1998,  and (ii) an  allocation  of certain of the  Authority  Financing
Notes. The promissory  notes contain  identical terms to the debt referred to in
items (i) and (ii) above. Immediately prior to such acquisition,  all of LILCO's
assets  employed  in the  conduct  of its  gas  distribution  business  and  its
non-nuclear electric generation business, and all common assets used by LILCO in
the  operation  and  management  of  its  electric  T&D  business  and  its  gas
distribution  business and/or its non-nuclear  electric generation business (the
"Transferred  Assets")  were sold to  KeySpan  Corporation  and  transferred  to
certain of our wholly-owned subsidiaries.

On May 28, 1998, immediately subsequent to the LIPA Transaction,  KSE was merged
with and into a subsidiary of KeySpan Corporation.

As a result of these  transactions,  holders of KSE common  stock  received  one
share of KeySpan  Corporation's common stock, par value $.01 per share, for each
share of KSE they owned and holders of LILCO  common stock  received  0.880 of a
share of KeySpan  Corporation  common  stock for each share of LILCO they owned.
Upon the closing of these  transactions,  former  holders of KSE and LILCO owned
32% and 68%, respectively, of KeySpan Corporation's common stock.

The  purchase  price  of  $1.223  billion  for the  acquisition  of KSE has been
allocated to assets acquired and liabilities  assumed based upon their estimated
fair values. The fair value of the utility assets acquired is represented by its
book value which  approximates the value recognized by the NYPSC in establishing
rates  for  regulated  utility  services.  The  estimated  fair  value  of KSE's
non-utility  assets  approximated  their  carrying  values.  At May 28, 1998, we
recorded  goodwill in the amount of $170.9 million,  representing  primarily the
excess of the acquisition  cost over the fair value of the net assets  acquired;
the goodwill is being amortized over 40 years.

Note 16. Costs Related to the LIPA Transaction and Special Charges

Special  charges for the nine months ended December 31, 1998 were $162.0 million
after-tax. These charges reflect, in part, non-recurring charges associated with
the LIPA  Transaction  of $107.9 million  after-tax.  Costs relating to the LIPA
Transaction  principally  reflect taxes  associated with the sale of assets (the
"Transferred  Assets") to us by LIPA; the write-off of certain regulatory assets
that  were no  longer  recoverable  under  various  LIPA  agreements;  and other
transaction  costs  incurred to consummate the LIPA  Transaction.  These charges
were offset,  in part, by tax benefits  relating to the deferred  federal income
taxes necessary to account for the difference between the carryover basis of the
Transferred  Assets for financial  reporting  purposes and the new increased tax
basis  of  the  assets,   and  tax  benefits   recognized   on  the  funding  of
postretirement benefits for our employees.

Special  charges also reflect an after-tax  impairment  charge of $54.1 million,
which  represents  our  share of the  impairment  charge,  recorded  by  Houston
Exploration to reduce the value of its proved

                                       80

<PAGE>



gas reserves in accordance  with the asset ceiling test  limitations  of the SEC
applicable to gas exploration and development operations accounted for under the
full cost method

Note 17. Supplemental Gas and Oil Disclosures (Unaudited)

This information  includes amounts  attributable to 100% of Houston  Exploration
and KeySpan Exploration and Production,  LLC at December 31, 2000.  Shareholders
other than  KeySpan  had a minority  interest  of  approximately  30% in Houston
Exploration  at December 31, 2000 and a 36% minority  interest in 1999.  Gas and
oil operations, and reserves, were predominantly located in the United States in
all years.
<TABLE>
<CAPTION>

Capitalized Costs Relating To Gas and Oil Producing Activities

At December 31,                                                                           2000                      1999
------------------------------------------------------------------------------- ------------------------- ----------------
                                                                                            (In Thousands of Dollars)
<S>                                                                                    <C>                      <C>
Unproved properties not being amortized                                         $         166,478     $            176,876
Properties being amortized - productive and nonproductive                               1,235,438                  979,615
                                                                                -----------------       ------------------
Total capitalized costs                                                                 1,401,916                1,156,491
Accumulated depletion                                                                    (577,240)                (512,465)
                                                                                -----------------       -----------------
Net capitalized costs                                                           $         824,676     $            644,026
------------------------------------------------------------------------------- -----------------       ------------------
</TABLE>

The  following  is a  break-out  of  the  costs  which  are  excluded  from  the
amortization calculation as of December 31, 2000, by year of acquisition:  2000-
$46.5  million , 1999 - $28.3 million and prior years $91.5  million.  We cannot
accurately  predict when these costs will be included in the amortization  base,
but it is  expected  that  these  costs will be  evaluated  within the next five
years.

<TABLE>
<CAPTION>
Costs Incurred in Property Acquisition, Exploration and Development Activities

Year Ended December 31,                            2000                    1999                   1998
----------------------------------------  ----------------------  ---------------------- ----------------------
                                                                (In Thousands of Dollars)
<S>                                             <C>                     <C>                    <C>
Acquisition of properties-
    Unproved properties                   $        7,992        $         13,107        $        33,803
    Proved properties                             40,960                  42,573                162,083
Exploration                                       70,511                  39,649                 55,611
Development                                      111,078                  87,965                 51,046
                                          ----------------------  ---------------------- ----------------------
Total costs incurred                      $      230,541        $        183,294        $       302,543
----------------------------------------  ----------------------  ---------------------- ----------------------
</TABLE>



                                                                  81

<PAGE>


<TABLE>
<CAPTION>

Results of Operations from Gas and Oil Producing Activities*

Year Ended December 31,                                             2000                1999                1998
------------------------------------------------------------  ----------------- -------------------- ------------------
                                                                              (In Thousands of Dollars)
<S>                                                                    <C>            <C>               <C>
Revenues                                                      $         274,209 $      150,581   $        127,124
                                                              ----------------- --------------   ----------------------
Production and lifting costs                                             36,929         23,851             21,166
Depletion                                                                95,364         74,051            209,838
                                                              ----------------- --------------   ----------------------
Total expenses                                                          132,293         97,902            231,004
                                                              ----------------- --------------   ----------------------
Income before taxes                                                     141,916         52,679           (103,880)
Income Taxes                                                             48,790         17,477            (37,410)
                                                              ----------------- --------------   ----------------------
Results of operations                                         $          93,126 $       35,202   $        (66,470)
------------------------------------------------------------  ----------------- --------------   ----------------------
</TABLE>
    *(excluding corporate overhead and interest costs)

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

Reserve Quantity Information Natural Gas (MMcf)

At December 31,                                             2000                    1999                   1998
--------------------------------------------  ---- ----------------------  ----------------------  ---------------------
<S>                                                    <C>                      <C>                    <C>
Proved reserves
    Beginning of year                                    534,308                 470,447                330,601
    Revisions of previous estimates                        4,479                  45,510                 (4,656)
    Extensions and discoveries                            77,643                  70,741                 67,272
    Production                                           (78,493)                (69,679)               (61,479)
    Purchases of reserves in place                         7,921                  20,779                139,994
    Sales of reserves in place                                 -                  (3,492)                (1,285)
                                                      -----------------    ---------------------   ---------------------
Proved reserves-
    End of year (1)                                      545,858                 534,306                470,447
--------------------------------------------------    -----------------    ----------------------  ---------------------
Proved developed reserves-
    Beginning of year                                    399,482                 369,931                256,632

    End of year (2)                                      431,536                 399,482                369,931
--------------------------------------------------    -----------------    ----------------------  ---------------------
</TABLE>
(1) Includes minority interest of 167,730;  189,427; and 169,361; in 2000, 1999,
and 1998, respectively.  (2) Includes minority interest of 133,271; 143,043; and
133,175; in 2000, 1999, and 1998, respectively.



                                       82

<PAGE>


<TABLE>
<CAPTION>
Crude Oil, Condensate and Natural Gas Liquids (MBbls)


At December 31,                                       2000                     1999                   1998
----------------------------------------------  -----------------------  ---------------------- ----------------------
<S>                                                 <C>                     <C>                    <C>
Proved reserves

    Beginning of year                                3,136                   1,650                  1,077
    Revisions of previous estimates                    108                     237                   (105)
    Extensions and discoveries                       4,326                   1,574                    249
    Production                                        (320)                   (258)                  (225)
    Purchases of reserves in place                     662                       2                    665
    Sales of reserves in place                           -                     (69)                   (11)
                                                -----------------------  ---------------------- ----------------------
Proved reserves-
    End of year (1)                                  7,912                   3,136                  1,650
----------------------------------------------  -----------------------  ---------------------- ----------------------
Proved developed reserves-
    Beginning of year                                2,059                   1,498                    914
    End of year (2)                                  2,126                   2,059                  1,498
----------------------------------------------  -----------------------  ---------------------- ----------------------
</TABLE>

(1) Includes minority  interest of 1,695; 890; and 594; in 2000,1999,  and 1998,
respectively.  (2) Includes minority interest of 573; 647; and 539 in 2000,1999,
and 1998, respectively.

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

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

At December 31,                                                                    2000                     1999
-----------------------------------------------------------------------  ------------------------  ----------------------
                                                                                      (In Thousands of Dollars)
<S>                                                                             <C>                     <C>
Future cash flows                                                        $        5,415,587     $         1,146,966
Future costs -
    Production                                                                     (558,384)               (194,527)
    Development                                                                    (182,242)               (128,645)
                                                                         ------------------------  ----------------------
Future net inflows before income tax                                              4,674,961                 823,794
Future income taxes                                                              (1,299,965)               (160,940)
                                                                         ------------------------  ----------------------
Future net cash flows                                                             3,374,996                 662,854
10% discount factor                                                              (1,209,237)               (182,222)
                                                                         ------------------------  ----------------------
Standardized measure of discounted future net cash flows (1)             $        2,165,759     $            480,632
-----------------------------------------------------------------------  ------------------------  ----------------------
</TABLE>
(1)  Includes  minority  interest  of  653,046  and  168,921  in 2000 and  1999,
respectively.

                                       83

<PAGE>


<TABLE>
<CAPTION>

Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserve Quantities

Year Ended December 31,                                                        2000                 1999                   1998
---------------------------------------------------------------------- --------------------  -------------------  ------------------
                                                                                           (In Thousands of Dollars)
<S>                                                                         <C>                   <C>                     <C>
Standardized measure -
    beginning of year                                                  $       480,632  $           396,060  $              315,380
Sales and transfers, net of production costs                                  (240,702)            (126,730)               (105,958)
Net change in sales and transfer prices,
    net of production costs                                                  2,142,932               47,330                (104,137)
Extensions and discoveries and improved
    recovery, net of related costs                                             472,658              106,076                  72,333
Changes in estimated future development costs                                  (38,839)             (25,730)                 (6,656)
Development costs incurred during the period
    that reduced future development costs                                       77,197               40,563                  15,891
Revisions of quantity estimates                                                 24,650               51,375                  (4,982)
Accretion of discount                                                           54,460               41,293                  37,706
Net change in income taxes                                                    (706,074)             (47,097)                 44,812
Net purchases of reserves in place                                              23,118               19,018                 155,259
Changes in production rates (timing) and other                                (124,273)             (21,526)                (23,588)
                                                                              --------              -------                 -------
Standardized measure -
    end of year                                                        $     2,165,759  $           480,632  $              396,060
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>

Average Sales Prices and Production Costs Per Unit

Year Ended December 31,                                                            2000                 1999               1998
--------------------------------------------------------------------------  -------------------  ------------------  ---------------
<S>                                                                              <C>                  <C>               <C>
Average sales price* Natural gas ($/MCF)                                            3.97                2.14              1.96
Oil, condensate and natural gas liquid ($/Bbl)                                     27.29               16.41             12.18
Production cost per equivalent MCF ($)                                              0.55                0.26              0.26
--------------------------------------------------------------------------  -------------------  ------------------  ---------------
</TABLE>

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


<TABLE>
<CAPTION>

Acreage
At December 31, 2000                                                                     Gross               Net
------------------------------------------------------------  -------------------  ------------------  ----------------
<S>                                                                                    <C>                <C>
Producing                                                                               335,017            217,407
Undeveloped                                                                             384,119            334,798
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>

Number of Producing Wells
At December 31, 2000                                                                     Gross               Net
------------------------------------------------------------  -------------------  ------------------  ----------------
<S>                                                                                    <C>                 <C>
Gas wells                                                                               1,307               889.6
Oil wells                                                                                   8                 3.4
--------------------------------------------------------------------------------  -------------------  -----------------
</TABLE>


<PAGE>

<TABLE>

Drilling Activity (Net)
<CAPTION>
Year Ended December 31,                   2000                                 1999                                 1998
-------------------------- ---------------------------------- ------------------------------------ ---------------------------------
                            Producing       Dry      Total        Producing      Dry       Total      Producing      Dry      Total
                            ---------       ---      -----        ---------      ---       -----      ---------      ---      -----
<S>                           <C>          <C>      <C>            <C>          <C>       <C>           <C>          <C>      <C>
Net developmental wells        40.4         4.4      44.8           29.7         3.1       32.8          19.2        4.6       23.8
Net exploratory wells          5.1          1.7       6.8            2.9         1.0        3.9          1.6         4.2       5.8
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


Wells in Process

At December 31, 2000                        Gross                   Net
------------------------------------- ------------------  ----------------------
Exploratory                                   5                     1.8
Developmental                                 5                     4.3
------------------------------------- ------------------  ----------------------



























                                       84

<PAGE>



Note 18.  Summary of Quarterly Information (Unaudited)


The  following is a table of financial  data for each quarter of KeySpan's  year
ended December 31, 2000.
<TABLE>
<CAPTION>
                                                                  (In Thousands of Dollars, Except Per Share Amounts)

                                              Quarter Ended       Quarter Ended      Quarter Ended      Quarter Ended
                                                 3/31/00             6/30/00            9/30/00          12/31/00 (a)
-------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>                  <C>                <C>               <C>
Operating revenues                           1,316,613            947,588            947,137           1,910,152
Operating income                               296,506            133,524             92,078             209,755
Net income                                     172,244             53,366             14,630              60,567
Earnings for common stock                      163,553             47,080             13,154              58,907
Basic and diluted earnings
        per common share   (b)                    1.22               0.35               0.10                0.44
Dividends declared                               0.445              0.445              0.445               0.445
-------------------------------------------------------------------------------------------------------------------------
</TABLE>


(a)  Reflects  an  after-tax  charge  of  $41.1  million  relating  to an  early
retirement and severance program.

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


The  following is a table of financial  data for each quarter of KeySpan's  year
ended December 31, 1999.
<TABLE>
<CAPTION>

                                                                    (In Thousands of Dollars, Except Per Share Amounts)

                                              Quarter Ended       Quarter Ended      Quarter Ended      Quarter Ended
                                                 3/31/99             6/30/99            9/30/99            12/31/99
-------------------------------------------------------------------------------------------------------------------------
<S>                                             <C>                 <C>                <C>                 <C>
Operating revenues                                961,108            543,526            538,469             911,510
Operating income                                  242,226             61,211             36,783             141,949
Net income                                        143,221             22,989              9,016              83,385
Earnings for common stock                         134,532             14,299                328              74,700
Basic and diluted earnings
    per common share   (a)                           0.94               0.10               0.00                0.56
Dividends declared                                  0.445              0.445              0.445               0.445
-------------------------------------------------------------------------------------------------------------------------
</TABLE>


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



                                       85

<PAGE>


                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have audited the  accompanying  Consolidated  Balance Sheet and  Consolidated
Statement of Capitalization of KeySpan  Corporation (a New York corporation) and
subsidiaries  as of  December  31,  2000 and  December  31, 1999 and the related
Consolidated Statements of Income,  Retained Earnings,  Comprehensive Income and
Cash Flows for the two years then ended and the nine months  ended  December 31,
1998.  These  financial   statements  are  the  responsibility  of  the  KeySpan
Corporation's  management.  Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion,  the financial  statements  referred to above present fairly, in
all material  respects,  the financial  position and  capitalization  of KeySpan
Corporation  and  subsidiaries as of December 31, 2000 and December 31, 1999 and
the  results of their  operations  and their cash flows for the years then ended
and the nine months ended  December  31, 1998,  in  conformity  with  accounting
principles generally accepted in the United States.

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


ARTHUR ANDERSEN LLP


January 25, 2001
New York, New York

                                       86
<PAGE>

<TABLE>
                                   SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
<CAPTION>


                                                                                          (In Thousands of Dollars)
-------------------------------------------------------------------------------------------------------------------
               Column A                  Column B                     Column C            Column D        Column E
-------------------------------------------------------------------------------------------------------------------
                                                                  Additions
                                                      ------------------------------
                                        Balance at    Charged to                                         Balance at
                                         beginning    costs and     Acquisitions and                       end of
             Description                 of period     expenses     LIPA Transaction     Net deductions     period
-------------------------------------------------------------------------------------------------------------------
<S>                                        <C>          <C>              <C>            <C>            <C>
Twelve months ended December 31, 2000
-------------------------------------

Deducted from asset accounts:
Allowance for doubtful accounts              $20,294      $26,455          $20,372        $17,643        $49,478

Additions to liability accounts:
Reserve for injuries and damages             $36,385      $20,074          $14,228        $19,121        $51,566
Reserve for environmental expenditures      $128,011      -                $42,637        $13,141       $157,507


Twelve months ended December 31, 1999
-------------------------------------

Deducted from asset accounts:
Allowance for doubtful accounts              $20,026      $15,793        -                $15,525        $20,294

Additions to liability accounts:
Reserve for injuries and damages             $29,075      $25,930        -                $18,620        $36,385
Reserve for environmental expenditures      $130,278       $5,000        -                 $7,267       $128,011


Nine months ended December 31, 1998
-------------------------------------

Deducted from asset accounts:
Allowance for doubtful accounts              $23,483      $11,064           $3,777        $18,298        $20,026

Additions to liability accounts:
Reserve for injuries and damages             $12,254       $8,690          $15,246         $7,115        $29,075
Reserve for environmental expenditures       $33,080      $48,920*         $48,278       -              $130,278
</TABLE>
        *Recorded as a Regulatory Asset for Future Recovery

<PAGE>


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

None.


                                    Part III


Item 10.  Directors and Executive Officers of the Registrant

A  definitive  proxy  statement  was filed  with the SEC on March 23,  2001 (the
"Proxy Statement"). The information required by this item is set forth under the
caption  "Executive  Officers  of the  Company"  in Part I hereof  and under the
captions  "Election  of  Directors"  and  "Section  16(a)  Beneficial  Ownership
Reporting  Compliance"  contained in the Proxy Statement,  which  information is
incorporated herein by reference thereto.

Item 11.  Executive Compensation

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

Item 12.  Security Ownership of Certain Beneficial Owners and Management

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

Item 13.  Certain Relationships and Related Transactions

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

Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K

1.           Financial Statements

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

      Report of Independent Public Accountants
      Consolidated Statement of Income for the year ended December 31,
            2000,  the year  ended  December  31,  1999,  and the nine
            months ended December 31, 1998.
      Consolidated  Statement of Retained  Earnings for the year ended
            December 31, 2000,  the year ended  December 31, 1999, and
            the nine months ended December 31, 1998.
      Consolidated Balance Sheet at December 31, 2000 and December 31, 1999.
      Consolidated Statement of Capitalization at December 31, 2000 and December
      31, 1999.
      Consolidated Statement of Cash Flows for the year ended December
            31, 2000,  the year ended  December 31, 1999, and the nine
            months ended December 31, 1998.
      Notes to Consolidated Financial Statements

2.              Financial Statements Schedules

Consolidated  Schedule of Valuation and  Qualifying  Accounts for the year ended
December 31, 2000,  the year ended  December 31, 1999, and the nine months ended
December 31, 1998.

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

<PAGE>

3.         Exhibits

Exhibits  listed  below  which  have been  filed  with the SEC  pursuant  to the
Securities Act of 1933, as amended,  or the Securities  Exchange Act of 1934, as
amended,  and which  were  filed as noted  below,  are  hereby  incorporated  by
reference  and  made a part of this  report  with the  same  effect  as if filed
herewith.


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

     3.2  ByLaws of the  Company In Effect on  September  10,  1998,  as amended
          (filed as Exhibit 3.1 to the Company's Form 8-K/A, Amendment No. 2, on
          September 29, 1998)

     4.1  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 Form S-3  Registration
          Statement No. 333-92003)

     4.2  Form of Medium-Term Note issued in connection with the issuance of the
          7 7/8% notes on February 1, 2000 (filed as Exhibit 4, to KeySpan  Form
          8-K on February 1, 2000)

     4.3* Form of Medium-Term Note issued in connection with the issuance of the
          6.9% notes on January 19, 2001.

     4.4  Indenture, dated as of November 1, 2000, between KeySpan and the Chase
          Manhattan  Bank,  as Trustee,  with the respect to the  issuance  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)

     4.5  Form of Note issued in connection  with the issuance of the 7.25% note
          issued on November  20, 2000 (filed as Exhibit 4-b to  KeySpan's  Form
          8-K on November 20, 2000)

     4.6  Form of Note issued in connection with the issuance of the 7.625% note
          issued on November  20, 2000 (filed as Exhibit 4-c to  KeySpan's  Form
          8-K on November 20, 2000)

     4.7  Form of Note issued in  connection  with the issuance of the 8.0% note
          issued on November  20, 2000 (filed as Exhibit 4-d to  KeySpan's  Form
          8-K on November 20, 2000)


<PAGE>


     4.8* Credit  Agreement,  dated as of September 22, 2000. among KeySpan,  as
          Borrower, the Several Lenders,  Citibank, N.A. and ABN Amro Bank, N.V.
          as   Co-Documentation   Agents,   J.P.  Morgan   Securities  Inc.,  as
          Syndication  Agent,  and The Chase Manhattan  Bank, as  Administrative
          Agent, for a $700,000,000 revolving credit loan.

     4.9* Credit  Agreement,  dated as of October 30, 2000,  among  KeySpan,  as
          Borrower, the Several Lenders,  Citibank,  N.A., as Syndication Agent,
          European American Bank, as Documentation Agent and The Chase Manhattan
          Bank, as  Administrative  Agent,  for a $700,000,000  revolving credit
          loan.

     4.10*Letter of Credit and Reimbursement Agreement, dated as of December 1,
          200, by and between KeySpan  Generation LLC and National  Westminister
          Bank PLC relating to the Electric  Facilities  Revenue Bonds ("EFRBs")
          Series 1997A .

     4.11-a  Participation  Agreements  dated as of  February  1, 1989,  between
          NYSERDA and The Brooklyn Union Gas Company  relating to the Adjustable
          Rate Gas Facilities  Revenue Bonds  ("GFRBs")  Series 1989A and Series
          1989B (filed as Exhibit 4 to The Brooklyn  Union Gas Company Form 10-K
          for the year ended September 30, 1989)

     4.11-b Indenture  of Trust,  dated  February 1, 1989,  between  NYSERDA and
          Manufacturers  Hanover  Trust  Company,  as  Trustee,  relating to the
          Adjustable  Rate GFRBs  Series  1989A and 1989B (filed as Exhibit 4 to
          the Brooklyn Union Gas Company Form 10-K for the year ended  September
          30, 1989)

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

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

     4.13-a First Supplemental  Participation  Agreement dated as of May 1, 1992
          to Participation  Agreement dated February 1, 1989 between NYSERDA and
          The  Brooklyn  Union Gas Company  relating to  Adjustable  Rate GFRBs,
          Series 1989A & B (filed as Exhibit 4 to The Brooklyn Union Gas Company
          Form 10-K for the year ended September 30, 1992)

     4.13-b First  Supplemental Trust Indenture dated as of May 1, 1992 to Trust
          Indenture  dated  February 1, 1989 between  NYSERDA and  Manufacturers
          Hanover


<PAGE>



          TrustCompany,  as Trustee,  relating to Adjustable Rate GFRBs,  Series
          1989A & B (filed as Exhibit 4 to The  Brooklyn  Union Gas Company Form
          10-K for the year ended September 30, 1992)

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

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

     4.15-a First Supplemental  Participation Agreement dated as of July 1, 1993
          to Participation  Agreement dated as of June 1, 1990,  between NYSERDA
          and The Brooklyn  Union Gas Company  relating to GFRBs Series C (filed
          as Exhibit 4 to The Brooklyn  Union Gas Company Form 10-K for the year
          ended September 30, 1993)

     4.15-b First Supplemental Trust Indenture dated as of July 1, 1993 to Trust
          Indenture  dated as of June 1, 1990 between NYSERDA and Chemical Bank,
          as  Trustee,  relating  to GFRBs  Series C (filed as  Exhibit 4 to The
          Brooklyn Union Gas Company Form 10-K for the year ended  September 30,
          1993)

     4.16-a Participation  Agreement,  dated July 15, 1993,  between NYSERDA and
          Chemical  Bank as Trustee,  relating to the GFRBs  Series D-1 1993 and
          Series D-2 1993 (filed as Exhibit 4 to The Brooklyn  Union Gas Company
          Form S-8 Registration Statement No. 33-66182)

     4.16-b  Indenture  of Trust,  dated  July 15,  1993,  between  NYSERDA  and
          Chemical  Bank as Trustee,  relating to the GFRBs  Series D-1 1993 and
          D-2 1993 (filed as Exhibit 4 to The  Brooklyn  Union Gas Company  Form
          S-8 Registration Statement No. 33-66182)

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

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

     4.18-a  Participation  Agreement,  dated as of  January  1,  1997,  between
          NYSERDA  and The  Brooklyn  Union Gas  Company  relating to GFRBs 1997
          Series A


<PAGE>



          (filed as Exhibit 4 to KeySpan  Energy  Corporation  Form 10-K for the
          year ended September 30, 1997)

     4.18-b Indenture of Trust, dated January 1, 1997, between NYSERDA and Chase
          Manhattan Bank, as Trustee,  relating to GFRBs 1997 Series A (filed as
          Exhibit 4 to KeySpan Energy  Corporation  Form 10-K for the year ended
          September 30, 1997)

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

     4.19-b  Indenture  of Trust dated as of December 1, 1997 by and between New
          York State Energy Research and Development Authority (NYSERDA) and The
          Chase  Manhattan  Bank,  as  Trustee,  relating  to the 1997  Electric
          Facilities Revenue Bonds (EFRBs),  Series A (filed as Exhibit 10(a) to
          the Company's Form 10-Q for the quarterly  period ended  September 30,
          1998)


     4.20-a Participation Agreement, dated as of October 1, 1999, by and between
          NYSERDA  and KeySpan  Generation  LLC  relating to the 1999  Pollution
          Control  Refunding  Revenue Bonds,  Series A (filed as Exhibit 4.10 to
          KeySpan's Form 10-K for the year ended December 31, 1999)

     4.20-b Trust  Indenture,  dated as of October 1, 1999,  by and  between New
          York State Energy Research and Development Authority (NYSERDA) and The
          Chase  Manhattan  Bank,  as Trustee,  relating  to the 1999  Pollution
          Control  Refunding  Revenue Bonds,  Series A (filed as Exhibit 4.10 to
          KeySpan's Form 10-K for the year ended December 31, 1999)

     4.20-c First Supplemental Trust Indenture,  dated as of January 1, 2000, by
          and between New York State Energy Research and  Development  Authority
          (NYSERDA) and The Chase  Manhattan  Bank, as Trustee,  relating to the
          GFRBs 1997 Series A (filed as Exhibit 4.11 to KeySpan's  Form 10-K for
          the year ended December 31, 1999)

     4.21 Indenture  dated as of December 1, 1989 between Boston Gas Company and
          The Bank of New York,  Trustee  (Filed as  Exhibit  4.2 to Boston  Gas
          Company's Form S-3 (File No. 33-31869)).

     4.22 Agreement of  Registration,  Appointment  and  Acceptance  dated as of
          November 18, 1992 among  Boston Gas  Company,  The Bank of New York as
          Resigning Trustee,  and The First National Bank of Boston as Successor
          Trustee. (Filed as an exhibit to Boston Gas Company's S-3 Registration
          S (File No. 33-31869))



<PAGE>



     4.23 Credit Agreement dated as of December 22, 1993 by and among Boston Gas
          Company,   Morgan  Guaranty  Trust  Company  of  New  York,   National
          Westminster  Bank PLC,  Shawmut Bank, N.A. and The First National Bank
          of Boston.  (Filed as Exhibit 10.17 to the Annual Report of Boston Gas
          Company on Form 10-K for the year ended December 31, 1993)

     4.24 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)

     4.25 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)

     4.26 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)

     4.27 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)

     4.28 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)

     4.29 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)

     4.30 Revolving  Credit  Agreement  for  Colonial  Gas  Company  dated as of
          September  12, 1997 (filed as Exhibit 4(e) to Colonial  Gas  Company's
          Form 10-Q for the quarter ended September 30, 1997)

     4.31 Revolving  Credit  Agreement  between  for  Colonial  Gas  Company and
          Massachusetts  Fuel  Inventory  Trust dated as of  September  12, 1997
          (filed as Exhibit  4(f) to Colonial  Gas  Company's  Form 10-Q for the
          quarter ended September 30, 1997)

     4.32 Trust Agreement dated as of June 22, 1990 between Colonial Gas Company
          (as Trustor)  and Shawmut  Bank,  N.A. (as Trustee)  (filed as Exhibit
          10(d) to Colonial  Gas  Company's  Form 10-Q for the period ended June
          30, 1990)

     4.33 Gas Service,  Inc. General and Refunding Mortgage Indenture,  dated as
          of June 30, 1987, as amended and supplemented by a First  Supplemental
          Indenture,  dated as of October 1, 1988, and by a Second  Supplemental
          Indenture,  dated as of  August  31,  1989  (filed as  Exhibit  4.1 to
          EnergyNorth,


<PAGE>



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

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

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

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

     4.37 Sixth Supplemental  Indenture,  dated as of September 15, 1997, to Gas
          Service,  Inc. General and Refunding Mortgage  Indenture,  dated as of
          June 30, 1987 (filed as Exhibit 4.5 to EnergyNorth Natural Gas, Inc.'s
          Amendment No. 1 to Registration  Statement on Form S-1, No. 333-32949,
          dated September 10, 1997)

     10.1 Agreement  and Plan of Merger  dated  November  4, 1999,  between  the
          KeySpan, Eastern Enterprises and ACJ Acquisition LLC (filed as Exhibit
          2 to KeySpan Form 8-K on November 5, 1999)

     10.2 Amendment  No. 1 to Agreement  and Plan of Merger,  dated  January 26,
          2000, between the KeySpan, Eastern Enterprises and ACJ Acquisition LLC

     10.3 Agreement  and  Plan  of  Reorganization   dated  as  of  November  4,
          1999,Eastern   Enterprises,   EE   Acquisition   Company,   Inc.   and
          EnergyNorth,  Inc.,  including  Amendment No. 1 dated November 4, 1999
          (filed as Exhibit 2.1 to Eastern's Form S-4 Registration Statement No.
          333-95693)

     10.4 Agreement and Plan of Merger dated as of June 26, 1997 by and among BL
          Holding  Corp.,  Long  Island  Lighting  Company,  Long  Island  Power
          Authority and LIPA Acquisition Corp. (filed as Annex D to Registration
          Statement on Form S-4, No. 333-30353 on June 30, 1997)

     10.5 Agreement of Lease between  Forest City Jay Street  Associates and The
          Brooklyn  Union Gas  KeySpan  dated  September  15,  1988 (filed as an
          exhibit to The Brooklyn Union Gas KeySpan Form 10-K for the year ended
          September 30, 1996)

     10.6 Stipulation of Settlement of federal Racketeer  Influenced and Corrupt
          Organizations Act Class Action and False Claims Action dated as of


<PAGE>



          February  27,  1989  among  the  attorneys  for Long  Island  Lighting
          KeySpan,  the  ratepayer  class,  the United States of America and the
          individual  defendants  named  therein  (filed as an  exhibit  to Long
          Island  Lighting  Company's  Form 10-K for the year ended December 31,
          1988)

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

     10.8 Power Supply  Agreement  between Long Island Lighting Company and Long
          Island Power  Authority dated as of June 26, 1997 (filed as Annex D to
          Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)

     10.9 Energy  Management  Agreement between Long Island Lighting Company and
          Long Island Power  Authority dated as of June 26, 1997 (filed as Annex
          D to Registration  Statement on Form S-4, No.  333-30353,  on June 30,
          1997)

     10.10Amended and Restated  Agreement  and Plan of Exchange and Merger dated
          June 26, 1997 between The  Brooklyn  Union Gas Company and Long Island
          Lighting  Company  dated  as of June  26,  1997  (filed  as Annex A to
          Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)

     10.11Amendment,  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)

     10.12-a*  Amendment  dated  as of  February  24,  2000,  to the  Employment
          Agreement  dated  September  10, 1998,  between  KeySpan and Robert B.
          Catell

     10.12-b Employment  Agreement dated September 10, 1998, between KeySpan and
          Robert B. Catell (filed as Exhibit  (10)(b) to KeySpan's Form 10-Q for
          the quarterly period ended September 30, 1998)

     10.13* Employment  Agreement effective as of March 1, 2001, between KeySpan
          and Craig G. Matthews

     10.14Employment  Agreement  effective as of July 29, 1999,  between KeySpan
          and Gerald Luterman (filed as Exhibit 10.10 to KeySpan's Form 10-K for
          the year ended December 31, 1999).

     10.15* Employment  Agreement dated as of November 8, 2000,  between KeySpan
          and Chester R. Messer.

     10.16Change of Control  Agreement  dated as of September 22, 1999,  between
          Eastern,  Boston Gas Company  and Chester R. Messer  (filed as Exhibit
          10.11.5  to  Eastern's  Form  10-Q  for  the  quarterly  period  ended
          September 30, 1999, File No. 1-2297).

     10.17* Employment  Agreement  dated as of November 8, 2000 between  KeySpan
          and Joseph A. Bodanza.


<PAGE>



     10.18* Change of  Control  Agreement  dated as of  September  22,  1999,
          between Eastern, Boston Gas Company and Joseph A. Bodanza

     10.19* Directors' Deferred Compensation Plan dated as of December 21, 2000

     10.20* 2000 Corporate  Annual  Incentive  Compensation and Gainsharing Plan
          effective January 1, 2000

     10.21Senior  Executive  Change of Control  Severance  Plan  effective as of
          October 30, 1998 (filed as Exhibit  10.20 to KeySpan Form 10-K for the
          year ended December 31, 1998)

     10.22Long Term Performance  Incentive  Compensation  Plan effective May 20,
          1999 (filed as Exhibit 10.3 to KeySpan's  Form 10-Q for the  quarterly
          period ended June 30, 1999).

     10.23Rights  Agreement  dated March 30,  1999,  between the KeySpan and the
          Rights  Agent  (filed as Exhibit 4 to KeySpan  Form 8-K,  on March 30,
          1999

     10.24Generating  Plant and Gas Turbine  Asset  Purchase and Sale  Agreement
          for Ravenswood for Ravenswood Generating Plants and Gas Turbines dated
          January 28, 1999, between the KeySpan and Consolidated  Edison Company
          of New York, Inc. (filed as Exhibit 10(a) to KeySpan Form 10-Q for the
          quarterly period ended March 31, 1999)

     10.25Lease Agreement dated June 9, 1999, between  KeySpan-Ravenswood,  Inc.
          and LIC Funding, Limited Partnership (filed as Exhibit 10.2 to KeySpan
          Form 10-Q for the quarterly period ended June 30, 1999)

     10.26Guaranty  dated  June 9,  1999,  from  the  KeySpan  in  favor  of LIC
          Funding,  Limited  Partnership  (filed as Exhibit 10.1 to KeySpan Form
          10-Q for the quarterly period ended June 30, 1999)

     10.27* Energy  Management  Agreement  dated  April 1, 2000,  by and between
          Keyspan Energy Trading Services LLC and Coral Energy Holding, L.P.

     10.28Redacted Gas Resource  Portfolio  Management  and Gas Sales  Agreement
          between  Boston Gas Company,  Colonial Gas Company,  Essex Gas Company
          (collectively, KEDNE) and El Paso Energy Marketing Company dated as of
          September  14,  1999,  as amended  (filed as  Exhibit  10.1 to Eastern
          Enterprises Form 10-K for the period ended December 31, 1999)

     10.29Indenture,  dated as of March 2, 1998, between The Houston Exploration
          Company and The Bank of New York,  as Trustee,  with  respect to the 8
          5/8%  Senior  Subordinated  Notes Due 2008  (including  form of 8 5/8%
          Senior  Subordinated  Note Due  2008)  (filed  as  Exhibit  4.1 to The
          Houston Exploration Company's  Registration Statement on Form S-4 (No.
          333-50235))


<PAGE>



     10.30Subordinated  Loan  Agreement  dated  November  30,  1998  between The
          Houston Exploration  Company and MarketSpan  Corporation d/b/a KeySpan
          Energy Corporation (filed as Exhibit 10.30 to The Houston  Exploration
          Company's  Annual Report on Form 10-K for the year ended  December 31,
          1998).

     10.31Subordination  Agreement  dated  November  25, 1998  entered  into and
          among MarketSpan  Corporation  d/b/a KeySpan Energy  Corporation,  The
          Houston  Exploration  Company  and  Chase  Bank  of  Texas,   National
          Association  (filed  as  Exhibit  10.31  to  The  Houston  Exploration
          Company's  Annual Report on Form 10-K for the year ended  December 31,
          1998 (File No. 001-11899)).

     10.32First  Amendment to  Subordinated  Loan Agreement and Promissory  Note
          between KeySpan  Corporation and The Houston Exploration Company dated
          effective as of October 27, 1999 (filed as Exhibit  10.14 to KeySpan's
          Form 10-K for the year ended December 31, 1999).

     10.33Restated   Exploration   Agreement  between  The  Houston  Exploration
          Company and KeySpan Exploration and Production, L.L.C., dated June 30,
          2000,  (filed as Exhibit  10.1 to The  Houston  Exploration  Company's
          Quarterly  Report on Form 10-Q for the  quarter  ended  September  30,
          2000, File No. 001-11899).

     10.34-a First  Amendment  and  Supplement  to Amended and  Restated  Credit
          Agreement  dated  May 4, 1999 by and  among  The  Houston  Exploration
          Company  and Chase  Bank of  Texas,  National  Association,  as agent,
          (filed as Exhibit 10.1 to The Houston Exploration  Company's Quarterly
          Report on Form 10-Q for the  quarter  ended  June 30,  1999  (File No.
          001-11899)).

     10.34-b Second Amendment to Amended and Restated Credit  Agreement  between
          The  Houston  Exploration  Company  and Chase Bank of Texas,  National
          Association,  as agent, dated October 6, 1999, (filed as Exhibit 10.32
          to The Houston Exploration Company's Quarterly Report on Form 10-Q for
          the quarter ended September 30, 1999 (File No. 001-11899)).

     10.34-c Third  Amendment  and  Supplement  to Amended and  Restated  Credit
          Agreement  between The Houston  Exploration  Company and Chase Bank of
          Texas, National  Association,  as agent, dated December 9, 1999 (filed
          as Exhibit  10.20 to KeySpan's  Form 10-K for the year ended  December
          31, 1999)

     10.35Indenture between Midland  Enterprises and State Street Bank and Trust
          Company  dated as of April 2, 1990  (filed as  Exhibit  2.2 to Midland
          Enterprises Registration Statement No 333-21120)

     10.36Indenture  between  Midland  Enterprises  and The Chase Manhattan Bank
          dated as of  September  29,  1998  (filed as  Exhibit  4.2 to  Midland
          Enterprises Registration Statement (File No. 333-61137)



<PAGE>



     21*  Subsidiaries of the Registrant

     23.1* Consent of Arthur Andersen LLP, Independent Auditors

     24.1*Power of Attorney  executed by Lilyan H. Affinito on February 6, 2001;
          which is  substantially  the same as Powers of Attorney made by Robert
          B. Catell on February 12, 2001;  Andrea S. Christensen on February 29,
          2001;  Howard R. Curd on  February  27,  2001;  Richard  N.  Daniel on
          February  29, 2001;  Donald H.  Elliott on February 11, 2001,  Alan H.
          Fishman  January 29, 2001,  Vicki L. Fuller on February  16, 2001;  J.
          Atwood Ives on January 30,  2001;  James R. Jones on February 1, 2001;
          James L.  Larocca on January 30, 2001;  Craig G.  Matthews on March 1,
          2001;  Stephen W.  McKessy on January  31,  2001;  Edward D. Miller on
          February 8, 2001 and James Q. Riordan February 1, 2001.

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

* Filed herewith


4.         Reports on Form 8-K

KeySpan filed Reports on Form 8-K on October 6, 2000, November 9, 2000, November
20, 2000, November 21, 2000, December 11, 2000 and January 25, 2001.

In our Report on Form 8-K, dated October 6, 2000, we filed historical  financial
statements of Eastern for the purpose of incorporating such information.

In our Report on Form 8-K,  dated November 9, 2000, we filed a copy of the press
release  reporting the closing of our transaction  with Eastern and EnergyNorth.
On November 20, 2000,  we filed a Report on Form 8-K  regarding  our issuance of
$1.65 billion aggregate principal amount of notes. Additionally, on November 21,
2000,  we filed a Report on Form 8- K to further  describe  the  acquisition  of
Eastern and EnergyNorth and to incorporate Eastern's Annual Report on Form 10-K,
for the period ended December 31, 1999.

On December 11, 2000, we filed a Report on Form 10-K, to include a press release
disclosing our  expectations on future  earnings.  On January 25, 2001, we filed
another Report on Form 8- K, disclosing our consolidated  earning for the fiscal
year ended December 31, 2000.










<PAGE>



                                   SIGNATURES

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

                                              KEYSPAN CORPORATION



March 30, 2001                                By: /S/Gerald Luterman
                                                  ----------------------
                                                  Gerald Luterman
                                                  Senior Vice President and
                                                  Chief Financial Officer


March 30, 2001                                By: /S/Ronald S. Jendras
                                                  --------------------
                                                  Ronald S. Jendras
                                                  Vice President, Controller and
                                                  Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended,
this  report has been  signed  below by the  following  persons on behalf of the
registrant and in the capacities indicated on March 30, 2001.


              *                Chairman of the Board and Chief Executive Officer
   ________________________            (Principal executive officer)
    Robert B. Catell

                               Senior Vice-President and Chief Financial Officer
                                          (Principal financial officer)
   /S/Gerald Luterman
   ------------------
   Gerald Luterman


                         Vice President, Controller and Chief Accounting Officer
  /S/Ronald S. Jendras                 Principal accounting officer)
  --------------------
    Ronald S. Jendras

           *
  ------------------------
     Lilyan H. Affinito                    Director


<PAGE>





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

                          *
              ------------------------
                   Howard R. Curd                      Director

                          *
              ------------------------
                  Richard N. Daniel                    Director

                          *
              ------------------------
                  Donald H. Elliott                    Director

                          *
              ________________________                 Director
                   Alan H. Fishman

                          *
              ________________________                 Director
                   Vicki L. Fuller

                          *
              ________________________                 Director
                   J. Atwood Ives

                          *
              ________________________                 Director
                   James R. Jones

                          *
              ________________________                 Director
                  James L. Larocca

                          *
              ________________________                 Director
                  Craig G. Matthews

                          *
              ________________________                 Director
                 Stephen W. McKessy

<PAGE>





                          *
              ________________________                 Director
                  Edward D. Miller


                          *
              ________________________                 Director
                  James Q. Riordan


               By:/s/ Gerald Luterman
                  Attorney-in-Fact

*  Such  signature has been affixed  pursuant to a Power of Attorney filed as an
   exhibit hereto and incorporated herein by reference thereto.