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

                                    FORM 10-K/A
                                 Amendment No. 1

       (Mark One)
 X     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
       ACT OF 1934

                   For the fiscal year ended December 31, 2002

                                       or

       Transition Report Pursuant to Section 13 or 15(d) of the Securities
        Exchange Act of 1934 For the transition period from ____ to____

                         Commission File Number 2-23416

                               BOSTON GAS COMPANY
                    D/B/A KEYSPAN ENERGY DELIVERY NEW ENGLAND
             (Exact Name of Registrant As Specified In Its Charter)

              Massachusetts                                04-1103580
     (State or other jurisdiction of        (I.R.S. Employer Identification No.)
      Incorporation or Organization)

            52 Second Avenue                           (781) 466-5000
       Waltham, Massachusetts 02453              (Registrant's Telephone Number)
(Address of Principal Executive Offices)

   Securities registered pursuant to Section 12(b) of the Act:

    Title of Each Class                                         Exchange
    -------------------                                         --------
            None                                                  None

   Securities registered pursuant to Section 12(g) of the Act: None


     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

Indicate the number of shares  outstanding of the  registrant's  class of common
stock as of March 1, 2002.

     All common stock, 514,184 shares, are held by KeySpan New England LLC .

     The  registrant  meets  the  conditions  set forth in  General  Instruction
(I)(1)(a)  and (b) of Form  10-K and is  therefore  filing  this  form  with the
reduced disclosure format.

                                EXPLANATORY NOTE

Boston Gas Company  hereby  amends its Form 10-K for the period from  January 1,
2002 to  December  31,  2002 (the "Form  10-K") as set forth in this Form 10-K/A
(the "Form  10-K/A").  This Form 10-K/A is being  amended  solely to include the
Section 906  Certifications  of the Chief Operating  Officer and Chief Financial
Officer dated March 28, 2003,  inadvertently  omitted from our previously  filed
Form 10-K, as well as the certifications,  dated the date hereof,  required as a
result of the filing of this amendment.

<PAGE>



                               BOSTON GAS COMPANY

                                    FORM 10-K

                       Fiscal Year Ended December 31, 2002

                                TABLE OF CONTENTS
<TABLE>
<CAPTION>
  Item
   No                                                           Topic                                                         Page
   --                                                           -----                                                         ----

                                                               PART I
        <S>                                                                                                                  <C>
  1.     Business
         General............................................................................................................   1
         Forward-Looking Information........................................................................................   1
         Markets and Competition............................................................................................   2
         Gas Throughput.....................................................................................................   2
         Gas Supply.........................................................................................................   3
         Regulation.........................................................................................................   4
         Seasonality and Working Capital....................................................................................   4
         Environmental Matters..............................................................................................   4
         Employees..........................................................................................................   4
  2.     Properties.........................................................................................................   5
  3.     Legal Proceedings..................................................................................................   5
  4.     Submission of Matters to a Vote of Security Holders................................................................   5
         Glossary...........................................................................................................   6

                                                               PART II

  5.     Market for the Registrant's Common Equity and Related Stockholder Matters..........................................   7
  6.     Selected Financial Data............................................................................................   7
  7.     Management's Discussion and Analysis of Financial Condition and Results of Operations..............................   7
  7A.    Quantitative and Qualitative Disclosures About Market Risk.........................................................  10
  8.     Financial Statements and Supplementary Data........................................................................  11
  9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...............................  11

                                                              PART III

10.      Directors and Executive Officers of the Registrant.................................................................  12
11.      Executive Compensation.............................................................................................  12
12.      Security Ownership of Certain Beneficial Owners and Management.....................................................  12
13.      Certain Relationships and Related Transactions.....................................................................  12
14.      Controls and Procedures............................................................................................  12

                                                               PART IV

15.      Exhibits, Financial Statement Schedules and Reports on Form 8-K....................................................  13
</TABLE>




<PAGE>



                                     PART I

Item 1.   Business.

General

Boston Gas Company D/B/A KeySpan Energy Delivery New England (referred to herein
as the "Company",  "we", "us" and "our"), is a gas distribution  company engaged
in  the  transportation  and  sale  of  natural  gas  to  approximately  563,000
residential, commercial and industrial customers in Boston, Massachusetts and 73
other  communities  in eastern  and  central  Massachusetts.  We are the largest
natural gas  distribution  company in New England and have been in business  for
180 years.

We are a  wholly-owned  subsidiary  of  KeySpan  New  England,  LLC ("KNE  LLC")
(formerly  known  as  Eastern   Enterprises).   On  November  8,  2000,  KeySpan
Corporation  ("KeySpan")  acquired  all of the  common  stock  of KNE  LLC.  The
transaction  was accounted  for as a purchase,  with KeySpan being the acquiring
company.  KNE  LLC has  owned  Boston  Gas  Company  since  1929.  KeySpan  is a
registered  holding  company  under  the  Public  Utility  Holding  Company  Act
("PUHCA") of 1935, as amended.  As a result, its activities,  as well as certain
activities  of its  subsidiaries,  including  the Company,  are regulated by the
Securities and Exchange Commission (the "SEC") under PUHCA.

For definition of certain  industry-specific  terms, see the Glossary at the end
of Part I and appearing on page 6.

The  Company  provides  local  transportation  services  and gas  supply  to all
customer classes.  Our services are available on a firm and non-firm basis. Firm
transportation  service  and  sales  are  provided  under  rate  tariffs  and/or
contracts  filed with the  Massachusetts  Department of  Telecommunications  and
Energy  ("Department")  that typically  obligate us to provide  service  without
interruption  throughout the year. Non-firm transportation service and sales are
generally provided to large  commercial/industrial  customers who can use gas or
another energy source  interchangeably.  Non-firm  services are provided through
individually  negotiated  contracts and, in most cases,  the price charged takes
into account the price of the customer's alternative fuel.

The Company offers unbundled services to all of its customers who are allowed to
purchase  local  transportation  from us  separately  from the  purchase  of gas
supply,  which the customer may buy from  third-party  suppliers.  We view these
third-party suppliers as partners in marketing gas and increasing throughput and
expect to work closely with them to facilitate the unbundling process and ensure
a smooth transition,  especially in the tracking and processing of transactions.
We implemented  programs to educate  customers about the opportunity to purchase
gas from third-party  suppliers,  while still relying on us for delivery.  As of
December 31, 2002, we had  approximately  5,800 firm  commercial  and industrial
transportation  customers.  Unbundled  service to residential  customers  became
available   on  November  1,  2000.   While  the   migration   of  customers  to
transportation-only  service  will lower our  revenues,  it has no impact on our
operating earnings.  We earn all of our margins on the local distribution of gas
and none on the resale of the commodity itself.

Forward-Looking Information

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  Disclosure 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.


                                       1
<PAGE>


Among the factors  that could cause  actual  results to differ  materially  are:
general  economic  conditions,  especially  in  Massachusetts;  fluctuations  in
weather;  volatility of energy prices,  including natural gas; 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  the  Company  to  successfully   reduce  its  cost  structure;
inflationary  trends  and  interests  rates;  implementation  of new  accounting
standards;  retention of key personnel;  creditworthiness  of counter-parties to
derivative  instruments and commodity  contracts;  and other risks detailed from
time to time in other reports and other  documents filed by the Company with the
SEC. For any of these statements,  the Company 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  Disclosure about Market
Risk," contained herein.


Markets and Competition

The  Company  competes  with other fuel  distributors,  primarily  oil  dealers,
throughout  its  service  territory.  We  believe  that  there  are  significant
opportunities  to increase  the number of natural gas  customers  by  converting
residential,  industrial  and  commercial  customers  from  oil-to-gas for space
heating purposes. However, increasing the number of natural gas customers cannot
be  predicted  with  certainty  and will depend on such  factors as the price of
competitive  energy  sources,  the level of  investment  required  and  customer
perception of relative value.

Gas Throughput

The following table in BCF provides  information  with respect to the volumes of
gas sold and transported by the Company during the three years 2000-2002.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
                                                                 Years Ended December 31,
                                                          2002            2001             2000
------------------------------------------------------------------------------------------------
<S>                                                    <C>             <C>              <C>
Residential                                               41.7            41.9             43.2
Commercial and industrial                                 20.9            21.9             25.4
Off-system sales                                           0.1             0.2              2.6
------------------------------------------------------------------------------------------------
     Total sales                                          62.7            64.0             71.2
Transportation of customer-owned gas                      65.6            61.9             55.8
Less: Off-system sales                                    (0.1)           (0.2)            (2.6)
------------------------------------------------------------------------------------------------
     Total throughput                                    128.2           125.7            124.4
------------------------------------------------------------------------------------------------
     Total firm throughput                               127.3           124.9            122.4
------------------------------------------------------------------------------------------------
</TABLE>


The above table excludes the effect of the accrual method of revenue recognition
as discussed in Note 1 of the Notes to Financial Statements.

In  2002,  residential  customers  comprised  91% of our  customer  base,  while
commercial   and   industrial   customers   accounted   for  the  remaining  9%.
Volumetrically,   residential   customers   accounted  for  33%  of  total  firm
throughput, while commercial and industrial customers accounted for 67% of total
firm throughput. Approximately 76% of commercial and industrial customers' total
throughput was  transportation-only  service. Sithe Energy, an independent power
generator  on  our  system,  was  responsible  for  approximately  25%  of  this
transportation  throughput  under a contract  which was renewed  through  March,
2004.  Sithe,  however,  has an  option  to  cancel  the  contract  with 60 days
notification.  They have also  notified us that they do not intend to extend the
contract  beyond  March  2004.  The  anticipated  loss in annual  transportation
revenues is expected to be $3.4 million, or $2.2 million, net of taxes.

No customer,  or group of customers  under common  control,  accounted for 2% or
more of total firm revenues in 2002.


                                       2
<PAGE>


Gas Supply

The following table in BCF provides information with respect to our sources of
supply during the three years 2000-2002.
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                                   Years Ended December 31,
                                                             2002            2001             2000
---------------------------------------------------------------------------------------------------
<S>                                                         <C>             <C>              <C>
Natural gas purchases                                        58.3            52.3             59.6
Underground storage withdrawal                                8.5             6.0             12.5
Liquefied natural gas ("LNG") purchases                       1.3             1.9              5.3
---------------------------------------------------------------------------------------------------
     Total source of supply                                  68.1            60.2             77.4
Company use, unbilled and other                              (5.4)            3.8             (6.2)
---------------------------------------------------------------------------------------------------
     Total sales                                             62.7            64.0             71.2
---------------------------------------------------------------------------------------------------
</TABLE>

Year-to-year  variations  in storage gas and unbilled gas reflect  variations in
end-of-year customer requirements, due principally to weather.

The vast majority of our gas supplies are  transported  on  interstate  pipeline
systems to our service territory pursuant to long-term contracts. Federal Energy
Regulatory Commission ("FERC") approved tariffs provide for fixed demand charges
for the firm capacity rights under these  contracts for the interstate  pipeline
companies that provide firm transportation service to our service territory. The
peak daily, annual capacity and contract expiration dates are as follows:
<TABLE>
<CAPTION>
                                                                            Capacity in BCF
------------------------------------------------------------------------------------------------------------------
                                                                                                     Expiration
                             Pipeline                                Daily              Annual         Dates
------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>                <C>       <C>
Algonquin Gas Transmission Company ("Algonquin")                      0.29                85.9     10/05-04/13
Tennessee Gas Pipeline Company ("Tennessee")                          0.24                88.1     10/08-11/12
------------------------------------------------------------------------------------------------------------------
                                                                      0.53               174.0
------------------------------------------------------------------------------------------------------------------
</TABLE>

In addition to capacity on the  Algonquin and  Tennessee  systems,  we have firm
capacity  contracts upstream of both pipelines in order to transport natural gas
purchased by us from various areas of gas production.

We have also  contracted  with pipeline  companies and others for the storage of
natural gas in underground  storage fields  located in  Pennsylvania,  New York,
Maryland and West Virginia. These contracts provide storage capacity of 16.3 BCF
and peak day  deliverability  of 0.18 BCF.  We utilize  existing  transportation
contracts to  transport  gas from the storage  fields to our service  territory.
Supplemental  supplies  of LNG and propane are  produced by and  purchased  from
foreign and domestic sources.

The Company operated under a portfolio management contract with El Paso Merchant
Energy Gas, L.P. ("El Paso"), from November 1, 1999 through October 31, 2002. El
Paso  was  responsible  for  providing  the  majority  of the city  gate  supply
requirements  to the Company,  in addition to managing  certain of the Company's
and certain affiliates  upstream capacity,  underground  storage and term supply
contracts.  We negotiated an interim  agreement with  Entergy-Koch that replaced
the expired El Paso agreement.  The interim  agreement  commenced on November 1,
2002 and extends  through  March 31,  2003.  On April 1, 2003,  a new  portfolio
management  agreement  will become  effective with  Entergy-Koch  with a term of
three years.


                                       3
<PAGE>


Peak day firm  throughput  in BCF was  0.86 in 2002,  0.63 in 2001,  and 0.80 in
2000.  We provide for peak  period  demand  through a  least-cost  portfolio  of
pipeline,  storage and supplemental supplies.  Supplemental supplies include LNG
and  propane  air,  which are  vaporized  mainly  at points on our  distribution
system.  We own  propane air  facilities  and one LNG  facility  in  Dorchester,
Massachusetts.  We also  lease two LNG  facilities  sited on land owned by us in
Salem and Lynn,  Massachusetts  and also lease  space in  facilities  located in
Providence,  Rhode Island and Everett,  Massachusetts.  We consider our peak day
sendout capacity,  based on our total supply  resources,  to be adequate to meet
the requirements of our firm customers.

Fluctuations  in utility gas costs have little impact on our  operating  results
because the current gas rate structure  includes a gas adjustment clause whereby
variations  between  actual gas costs incurred and gas costs billed are deferred
and subsequently refunded to or collected from customers.

Regulation

Our  operations  are  subject  to  Massachusetts   statutes  applicable  to  gas
utilities.  Rates for gas sales and transportation service,  distribution safety
practices,  issuance of securities and affiliate  transactions  are regulated by
the Department.  Rates for  transportation  service and gas sales are subject to
approval  by and are on file  with the  Department.  Our cost of gas  adjustment
clause,  allows for a semiannual  adjustment,  and based on certain criteria,  a
monthly  adjustment  of billing  rates for firm gas sales to reflect  the actual
cost of gas delivered to customers, including demand charges for capacity on the
interstate pipeline system. Similarly, through our local distribution adjustment
clause,  we collect the actual cost of approved energy  efficiency  programs and
the cost of  remediating  former  manufactured  gas  plant  sites  from all firm
customers,  including those  purchasing gas supply from third parties.  For more
detailed information regarding regulation,  see Item 7. "Management's Discussion
and  Analysis of  Financial  Condition  and Results of  Operation-Other  Matters
-Regulation."


Seasonality and Working Capital

Our  revenues,  earnings  and  cash  flows  are  highly  seasonal  because  most
transportation   services  and  sales  are  directly   related  to   temperature
conditions.  Since the majority of revenues  are billed in the November  through
April heating season,  significant  cash flows are generated from late winter to
early summer.  In addition,  through the cost of gas adjustment  clause, we bill
our customers  over the November - April heating  season for the majority of the
pipeline  demand  charges  incurred  and paid by us over the entire  year.  This
timing  difference,  along with other costs of gas distributed but unbilled,  is
reflected  as deferred  gas costs on the Balance  Sheet and is financed  through
short-term borrowings. Short-term borrowings are also required from time to time
to finance normal business operations. As a result of these factors,  short-term
borrowings are generally highest during the late fall and early winter.

Environmental Matters

We have or  share  responsibility  under  applicable  environmental  law for the
remediation  of former  manufactured  gas  plant  operations,  including  former
operating plants, gas holder locations and satellite disposal sites. Information
with  respect to the  remediation  of these  sites may be found in Note 9 of the
Notes to  Financial  Statements.  Such  information  is  incorporated  herein by
reference.

Employees

As of December 31, 2002, Boston Gas had approximately 775 employees, 87% of whom
are  organized  in  local  unions  with  which  we  have  collective  bargaining
agreements.  In March 2002,  we entered into a four-year  collective  bargaining
agreement with the largest bargaining units representing union employees;  these
agreements expire in 2006.


                                       4
<PAGE>


Item 2.   Properties.

We operate three LNG facilities in Dorchester,  Salem, and Lynn,  Massachusetts.
These  facilities  provide us with local storage of gas,  because the stored LNG
can be vaporized  into our  distribution  system to  supplement  pipeline gas in
periods of high demand.  We own the  Dorchester  facility.  We also own the real
property at the Salem and Lynn facilities and rent the storage  facilities under
a long-term lease  arrangement.  In addition,  we own propane-air  facilities at
various locations throughout our service territory.

On December 31, 2002, our distribution system included approximately 6,200 miles
of gas mains, 450,000 services and 563,000 active customer meters. A majority of
the gas  mains  consist  of cast  iron and bare  steel,  which  require  ongoing
maintenance and replacement.

Our gas mains and  services  are  usually  located  on  public  ways or  private
property  not  owned by us. In  general,  our  occupation  of such  property  is
pursuant to easements, licenses, permits or grants of location. Except as stated
above, the principal items of property are owned.

In 2002 our  capital  expenditures  were  approximately  $110  million.  Capital
expenditures  were principally made for improvements to the distribution  system
and for system expansion to meet customer growth. We plan to spend approximately
$100 million, including costs of removal, for similar purposes in 2003.

Information  with  respect  to the  Company'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.

In addition,  we lease other office and building space,  office  equipment,  and
vehicles.  Our  properties  are  adequate  and  suitable to meet our current and
expected  business  requirements.   Moreover,   their  productive  capacity  and
utilization meet our needs for the foreseeable  future.  We continually  examine
our real property and other property for its  contribution  and relevance to our
businesses and when such properties are no longer  productive or suitable,  they
are disposed of as promptly as possible.  In the case of leased office space, we
anticipate no significant  difficulty in leasing alternative space at reasonable
rates in the event of the expiration, cancellation or termination of a lease.

Item 3.   Legal Proceedings.

Other than routine litigation incidental to the business,  there are no material
pending legal proceedings involving the Company.

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

No matters were submitted to a vote of Security Holders in the fourth quarter of
2002.


                                       5
<PAGE>


Glossary

BCF--Billions of cubic feet of natural gas at 1,000 Btu per cubic foot.

Bundled  Service--Two  or more  services  tied  together  as a  single  product.
Services include gas sales at the city gate,  interstate  transportation,  local
transportation,   balancing  daily  swings  in  customer  loads,   storage,  and
peak-shaving services.

Capacity--The  capability  of pipelines and  supplemental  facilities to deliver
and/or store gas.

City Gate--Physical interconnection between an interstate pipeline and the local
distribution company.

Core  Customer--Generally,  customers with no readily  available energy services
alternative.

Dekatherm--1,000 cubic feet of natural gas at 1,000 Btu per cubic foot.

Firm Service--Sales and/or transportation service provided without interruption.
This could be for the year,  or for an agreed  upon  period  less than 365 days.
Firm  services  are  provided   under  either  filed  rate  tariffs  or  through
individually negotiated contracts.

Gas Marketer (Broker)--A non-regulated buyer and seller of gas.

Interstate  Transportation--Transportation  of gas by an interstate  pipeline to
the city gate.

Local  Distribution  Company  (LDC)--A  utility  that  owns and  operates  a gas
distribution  system  for the  delivery  of gas  supplies  from the city gate to
end-user facilities.

Local  Transportation  Service--Transportation  of gas by the LDC  from the city
gate to the customer's burner tip.

Non-Core   Customers--Generally,   those   customers  with  readily   available,
economically viable energy alternatives to gas.

Non-Firm  Service--Sales and transportation  service offered at a lower level of
reliability  and cost.  Under this service,  the LDC can interrupt  customers on
short notice, typically during the winter season. Non-firm services are provided
through individually  negotiated contracts and, in most cases, the price charged
takes into account the price of the customer's energy alternative.

Performance-Based Regulatory Plan--Incentive ratemaking mechanism, whereby rates
are adjusted annually pursuant to a pre-determined  formula tied to a measure of
inflation,  less a productivity  offset,  subject to the  achievement of service
quality measures and the incurrence of exogenous factors.

Throughput--Gas volume delivered to customers through the LDC's gas distribution
system.

Unbundled  Service--Service  that is  offered  and  priced  separately,  such as
separating  the cost of gas commodity  delivered to the LDC's city gate from the
cost of  transporting  the gas  from the city  gate to the end  user.  Unbundled
services  can also  include  daily or monthly  balancing,  back-up  or  stand-by
services and pooling.  With  unbundled  services,  customers  typically have the
opportunity to select only the services they desire.

Utility  Money  Pool--KeySpan  has  established  a money  pool  for its  utility
subsidiaries  for  purposes  of  reducing  outside  borrowings  and  for a  more
efficient  use of funds.  Utility  subsidiaries  can borrow  from/or lend to the
money  pool  depending  upon its  financing  needs.  The money pool is funded by
commercial  paper  and  operating  funds  of  net  lenders  to the  pool.  It is
administered by a wholly-owned  KeySpan  subsidiary,  KeySpan Corporate Services
LLC ("KCS") and its operation is subject to PUHCA regulation.


                                       6
<PAGE>


                                     PART II

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

KNE LLC, a  wholly-owned  subsidiary  of KeySpan  Corporation,  is the holder of
record of all of the outstanding common equity securities of the Company.

Item 6.   Selected Financial Data.

Not required.

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

RESULTS OF OPERATIONS

The net loss  applicable  for common stock for the year ended  December 31, 2002
was $3.4 million  compared to a net loss of $31.3 million in the prior year. The
improvement of $27.8 million, or 89%, over the prior year is due primarily to an
increase in operating  margin and the  discontinuance  of goodwill  amortization
offset, in part, by higher interest expense and income taxes.

Operating  revenues for the year ended  December 31, 2002 declined $190 million,
or 23%, from 2001. The decrease was due to a decline of $213 million, or 38%, in
the cost of gas sold to customers,  which are fully recovered  through revenues.
The decrease in gas costs reflects a 40% decline in the average  commodity price
of gas combined  with a 4.3% decrease in  throughput.  The decline in throughput
was primarily due to  significantly  warmer weather in the first quarter of 2002
versus the prior year's first quarter.

Our gas rate structure includes a gas adjustment  clause,  pursuant to which gas
costs are fully recovered. Further, variations between actual gas costs incurred
and gas costs billed are deferred and refunded to or collected from customers in
a  subsequent  period.  As a result,  fluctuations  in the cost of gas sold have
little or no impact on operating margin.

Operating  margin  (revenues  less the  cost of gas  sold)  for the  year  ended
December 31, 2002 increased $23.0 million, or 8.5%, from the year ended December
31, 2001.  Primarily  contributing  to the  improvement was an increase of $13.8
million due to customer growth, a base rate increase of $3.6 million  associated
with our  performance-based  rate plan ("PBR") (see "Other  Matters-Regulation")
and an additional  benefit of $6.3 million  attributable  to the favorable court
decision which resulted in the  elimination  of an  "accumulated  inefficiencies
factor" included in the PBR (see "Other Matters-Regulation"). Other gas margins,
which  include  sales to non-core  customers  and  regulatory  rate  incentives,
increased $3.9 million.

The improvement in operating  margin was partially offset by a reduction of $1.6
million  as a result of lower gas  throughput  due to the warmer  first  quarter
weather and a net reduction of $3.3 million in revenues  associated with weather
derivatives that hedged approximately 7.4% colder than normal weather during the
fourth quarter.  (See Item 7A.  "Quantitative and Qualitative  Disclosures About
Market Risk -Weather Derivatives" for further information).

Total operating expenses, excluding goodwill amortization, declined $5.1 million
or 2% over the prior year.  Operations and  maintenance  expense  decreased $2.9
million,  or 1.8% over the prior year,  primarily  due to cost saving  synergies
realized  during  the year as well as lower  bad debt  expense  due to the lower
average levels of customer  receivables in 2002. These decreases were offset, in
part, by allocated  payroll  taxes  associated  with general and  administrative
services provided by KCS, which were included in 2002 operations and maintenance
expense,  whereas  in 2001,  these  general  and  administrative  services  were
provided by our employees and the related taxes were charged to operating taxes.


                                       7
<PAGE>


Depreciation  expense  increased  as a result of  continued  investments  in the
distribution  infrastructure.  Operating  taxes  decreased  primarily due to the
lower payroll taxes (as discussed above) and lower property taxes. In accordance
with SFAS 142, as of January 1, 2002, we are no longer amortizing goodwill.  For
the year ended December 31, 2001, amortization of goodwill was $19.4 million.

For the year ended  December  31, 2002,  interest  expense on long term debt was
comparable  to the prior  year.  For the year ended  December  31,  2002,  other
interest expense  increased $6.8 million,  or 15.5%,  versus 2001. This increase
resulted  from a full year of  interest  expense  in 2002  versus  six months of
interest  expense in 2001 on a $50 million advance from KeySpan made on June 30,
2001.  For  the  year  ended  December  31,  2002,   interest   capitalized  for
construction  increased $1.8 million over the prior year  principally due to the
investment in software in 2002.

Income tax expense for the year ended December 31, 2002 increased  $12.4 million
from 2001. The increase in expense is primarily  attributable  to higher taxable
income.

LIQUIDITY AND CAPITAL RESOURCES

In 2002,  we received  capital  contributions  of $200 million from KNE LLC. The
proceeds were used to pay down borrowings from the utility money pool.

On September  1, 2002,  we made the required  $1.5 million  annual  sinking fund
payment on our 6.42%  Cumulative  Preferred  Stock. For details on the Preferred
Stock, see Note 4 in the Notes to Financial Statements.

On November 8, 2000,  KCS, a subsidiary  of KeySpan,  became an affiliate of the
Company, as a result of KeySpan's acquisition of KNE LLC. KCS provides financing
requirements  to the Company for working  capital and gas inventory  through the
Company's  participation  in a  utility  money  pool.  Interest  charged  equals
interest  incurred  by KeySpan to borrow  funds to meet the needs of the Company
plus a proportional share of the administrative  costs incurred in obtaining the
required funds.

As part of the transaction with KeySpan,  the Company recorded in November 2000,
a $600 million  advance  payable to KeySpan.  During  2001,  an  additional  $50
million advance was received from KeySpan and a $50 million dividend was paid to
KeySpan.  Interest charges are equal to the interest incurred by KeySpan on debt
borrowings issued by KeySpan and recorded on the books of the Company.  Issuance
expense is charged to the Company  from  KeySpan  equal to the  amortization  of
actual  issuance  costs  incurred  by  KeySpan on its debt  borrowings.  KeySpan
amortizes these costs over the life of the related KeySpan borrowings.

We have $210 million of Medium-Term  Notes outstanding at December 31, 2002. For
details on debt, see Note 3 in the Notes to Financial Statements. The ratings on
the  long-term  debt have  remained on stable  outlook.  At December  31,  2002,
Moody's Investor Services and Standard & Poor's rated the debt A2.

As discussed,  revenues,  earnings and cash flows are highly seasonal. Since the
majority of revenues  are billed  during the heating  season,  significant  cash
flows  are  generated  from  late  winter  to early  summer.  Alternatively,  in
preparation for the heating season (i.e. purchasing and storing of natural gas),
short-term borrowings are highest during the late fall and early winter.

The Company  expects  capital  expenditures  for 2003 to be  approximately  $100
million,  including costs of removal.  Capital  expenditures will be largely for
system  expansion to meet customer growth and  improvements to the  distribution
system.

The Company  believes that projected cash flow from  operations,  in combination
with currently  available  resources (i.e. utility money pool), is sufficient to
meet 2003 capital expenditures, working capital requirements, preferred dividend
payments and normal debt repayments.


                                       8
<PAGE>


OTHER MATTERS

Regulation

Our  operations  are  subject  to  Massachusetts   statutes  applicable  to  gas
utilities.  Rates for gas sales and transportation service,  distribution safety
practices,  issuance of securities and affiliate  transactions  are regulated by
the Department.  Rates for  transportation  service and gas sales are subject to
approval  by and are on file  with the  Department.  Our cost of gas  adjustment
clause,  billed to firm sales customers,  allows for the semiannual  adjustment,
and based on certain  criteria,  a monthly  adjustment of billing rates for firm
gas sales to reflect the actual cost of gas  delivered to  customers,  including
demand  charges  for  capacity on the  interstate  pipeline  system.  Similarly,
through its local distribution adjustment clause, we collect the actual costs of
approved  energy  efficiency   programs  and  the  cost  of  remediating  former
manufactured gas plant sites from all firm customers, including those purchasing
gas supply from third parties.

The  Company's  rates for local  transportation  service had been  governed by a
five-year  performance-based  rate plan (the "Plan")  approved in D.P.U.  96-50.
Under the Plan,  our local  transportation  rates had been adjusted  annually to
reflect  inflation  for the  previous  12 months and  reduced by a  productivity
factor.  The Plan also  provided for  penalties  if we failed to meet  specified
service quality measures, with a maximum potential exposure of $1 million. There
was a margin sharing mechanism whereby 25% of earnings in excess of a 15% return
on  year-ending  equity  were  to  be  passed  back  to  ratepayers.  Similarly,
ratepayers  were to absorb 25% of any shortfall below a 7% return on year-ending
equity.   Although  the  Plan  expired  October  31,  2002,  distribution  rates
established under the Plan continue to be effective.  We expect to propose a new
rate plan with the Department during the spring of 2003.

In D.P.U.  96-50,  the  productivity  factor  was set at 1.50%  and the  service
quality  penalty was  expanded  beyond the $1 million  proposed in our Plan.  We
appealed  D.P.U.  96-50 and on January  16,  2001,  the  Department  limited the
maximum service quality  adjustment to $1 million and adjusted the  productivity
factor to 1.0%.  On January 30,  2001,  we appealed the  imposition  of the 0.5%
accumulated inefficiencies adjustment and on March 7, 2002, the Supreme Judicial
Court  of  Massachusetts  ruled  in  favor of the  Company  and  eliminated  the
accumulated  inefficiencies  factor of 0.5%,  thereby  reducing the productivity
factor to 0.5%.

On November 1, 2001, the Department  issued an order requiring all Massachusetts
electric and gas utilities to develop service quality plans effective January 1,
2002. On April 17, 2002,  the Department  issued an order  approving our service
quality  plan that was  filed  with the  Department  on March 1,  2002.  Service
quality will be tracked and measured against historical benchmarks.  Our failure
to meet the  Department's  service  quality  standards  is  subject to a maximum
penalty equivalent to 2% of its distribution service revenues.  Each measurement
period will be a calendar year. The first measurement period began on January 1,
2002. For the year ended 2002, we met the Department's service quality standards
and were not subject to any penalties.

All of our customers  are eligible to purchase  unbundled  local  transportation
service from the Company and to purchase their gas supply from third parties. In
2000,  the  Department  approved  Model  Terms and  Conditions  for  residential
customer tariffs effective  November 1, 2000. The Model Terms and Conditions are
consistent with the Department's  order of February 1, 1999 which provided that,
for  a  five-year   transition  period,   local  distribution   company  ("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 because of
the migration of customers to the gas supply service of third parties, the costs
of upstream  interstate gas pipeline capacity  purchased by the Company to serve
firm  customers  would be  absorbed  by the LDC or other  customers  through the
transition  period.  The  Department  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 at  Massachusetts
city gates to support  customer  requirements  and growth.  In year three of the
five-year  transition  period,  the Department intends to evaluate the extent to
which the upstream  capacity market for  Massachusetts  is workably  competitive
based on a number of factors and accelerate or decelerate the transition  period
accordingly.


                                       9
<PAGE>


Securities and Exchange Commission Regulation

The  Company,  as a wholly  owned  subsidiary  of  KeySpan,  is  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.

As a result of an order  issued by the SEC on  November 8, 2000,  in  connection
with KeySpan's  acquisition of KNE LLC and  EnergyNorth, Inc., and as amended on
December 6, 2002 and February 14, 2003,  we are committed  through  December 31,
2003 to have common  equity of at least 30% of total  capitalization,  including
affiliated  debt.  At December  31, 2002,  our common  equity was 35.8% of total
capitalization, including affiliated debt.

Environmental Matters

The Company has or shares responsibility under applicable  environmental law for
the remediation of former  manufactured gas plant  operations,  including former
operating plants, gas holder locations and satellite disposal sites. Information
with  respect to the  remediation  of these  sites may be found in Note 9 of the
Notes to  Financial  Statements.  Such  information  is  incorporated  herein by
reference.

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 towards a more competitive and deregulated environment. In
addition,  we are  exposed  to  commodity  price  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

In July 1997, the Department 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
Department in November 1998. In February  1999, the Department  issued its order
on  how  unbundling  of  natural  gas  service  will  proceed.  For a  five-year
transition period, the Department determined that LDC's 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  LDC's to  serve  firm  customers  will be  absorbed  by other
customers through the transition period. The Department also found that, through
the  transition  period,  LDCs will retain primary  responsibility  for upstream
capacity  planning and procurement to assure that adequate capacity is available
to support customer  requirements and growth. The Department  approved the LDC's
Terms and  Conditions of  Distribution  Service that conform to the settled upon
model terms and  conditions.  Since  November  1, 2000,  all  Massachusetts  gas
customers  have the option to  purchase  their gas  supplies  from  third  party
sources other than the LDC's.

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.


                                       10
<PAGE>


Commodity Price and Credit Risk

Weather Derivatives

The utility  tariffs  associated  with our  operations  do not contain a weather
normalization  clause. As a result,  fluctuations from normal weather may have a
significant  positive  or  negative  effect on the  results  of  operations.  To
mitigate  the  effect of  fluctuations  from  normal  weather  on our  financial
position and cash flows,  we sold heating  degree-day call options and purchased
heating-degree day put options for the November 2002 - April 2003 winter season.
With respect to sold call options,  we are required to make a payment of $40,000
per heating degree day to our  counter-parties  when actual weather  experienced
during the November 2002 - April 2003 time frame is above 4,470  heating  degree
days, which equates to approximately 1% colder than normal weather. With respect
to  purchased  put  options,  we will  receive a $20,000 per heating  degree day
payment  from our  counter-parties  when actual  weather is below 4,150  heating
degree days, or is  approximately  7% warmer than normal.  Based on the terms of
such contracts, as discussed in Note 11 of the Notes to Financial Statements, we
account  for  such  instruments  pursuant  to the  requirements  of  EITF  99-2,
"Accounting  for  Weather  Derivatives."  In this  regard,  we account  for such
instruments  using the  "intrinsic  value method" as set forth in such guidance.
During the fourth quarter of 2002,  weather was  approximately  7.4% colder than
normal and we recorded a $3.3 million reduction to revenues with a corresponding
liability due to our counter-parties.

Our derivative  contracts are primarily  used to manage  exposure to market risk
arising  from  changes  in demand as a result of weather  colder or warmer  than
normal.  In the  event of  nonperformance  by a  counter-party  to a  derivative
contract,  the desired impact may not be achieved.  The risk of a  counter-party
nonperformance  is generally  considered  credit risk and is actively managed by
assessing each counter-party  credit profile and negotiating  appropriate levels
of collateral and credit support.

Physically-Settled Commodity Derivative Instruments:

On April 1, 2002 we implemented  Derivative  Implementation Group ("DIG") C16 of
SFAS 133,  "Accounting for Derivative  Instruments and Hedging  Activities",  as
amended   and   interpreted,   incorporating   SFAS  137  and  138  and  certain
implementation  issues  (collectively  "SFAS  133").  Issue C16  relates  to the
exemption (as normal  purchases  and normal  sales) of contracts  that combine a
forward  contract and a purchased  option  contract.  Based upon a review of our
physical  commodity  contracts,  we  determined  that certain  contracts for the
physical  purchase of natural gas can no longer be exempted as normal  purchases
from the requirements of SFAS 133. Since these contracts are for the purchase of
natural gas sold to regulated firm gas sales customers, the accounting for these
contracts is subject to SFAS 71. Therefore, changes in the market value of these
contracts are recorded as a deferred asset or deferred  liability on the Balance
Sheet.

Item 8.   Financial Statements and Supplementary Data.

Information  with  respect to this item appears  commencing  on Page F-1 of this
Report. Such information is incorporated herein by reference.


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

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


                                       11
<PAGE>


                                    PART III

Item 10.   Directors and Executive Officers of the Registrant.

Not required.


Item 11.   Executive Compensation.

Not required.


Item 12.   Security Ownership of Certain Beneficial Owners and Management.

Not required.


Item 13.   Certain Relationships and Related Transactions.

Not required.

Item 14.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes In Internal Controls

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


                                       12
<PAGE>


                                     PART IV

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

List of Financial Statements and Financial Statement Schedules.

Information with respect to these items appears on Page F-1 of this Report. Such
information is incorporated herein by reference.

(3) List of Exhibits.

3.1  Restated Articles of Organization,  as amended (Filed as Exhibit 3.1 to the
     registration statement of the Company on Form S-3 (File No. 33-48525)).*

3.2  By-Laws of the Company as amended  (Filed as Exhibit 1 to the Annual Report
     of the Company on Form 10-K for the year ended  December 31, 1976 (File No.
     2-23416)).*

     (Note: Certain instruments with respect to long-term debt of the Company or
     its subsidiary are not filed herewith since no such  instrument  authorizes
     securities in an amount greater than 10% of the total assets of the Company
     and its subsidiary on a consolidated  basis.  The Company agrees to furnish
     to the Securities and Exchange  Commission  upon request a copy of any such
     omitted instrument of the Company or its subsidiary.)

4.1  Indenture  dated as of December 1, 1989 between the Company and The Bank of
     New York,  Trustee (Filed as Exhibit 4.2 to the  registration  statement of
     the Company on Form S-3 (File No. 33-31869)).*

4.2  Agreement of Registration,  Appointment and Acceptance dated as of November
     18, 1992 among the Company,  The Bank of New York as Resigning Trustee, and
     The  First  National  Bank of  Boston as  Successor  Trustee.  (Filed as an
     exhibit  to  registration  statement  of the  Company on Form S-3 (File No.
     33-31869)).*

4.3  Utility Money Pool Agreement. (filed as an exhibit 4.3 to the Annual Report
     of the company on Form 10-K for the year ended December 31, 2000).*

10.1 Gas Transportation  Contract between the Company and Tennessee Gas Pipeline
     Company  dated as of  September 1, 1993  providing  for  transportation  of
     approximately  94,000  dekatherms  of natural gas per day (Filed as Exhibit
     10.1 to the  Annual  Report of the  Company on Form 10-K for the year ended
     December 31, 1993).*

10.2 Gas  Transportation  Contract  between the Company and Texas  Eastern dated
     October 29, 1999  providing  for  transportation  of  approximately  48,133
     dekatherms  of natural  gas per day.  (Filed as Exhibit  10.2 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1999).*

10.3 Gas  Transportation  Contract  between the Company and Texas  Eastern dated
     December 30, 1993  providing for  transportation  of  approximately  32,000
     dekatherms  of natural  gas per day.  (Filed as Exhibit  10.3 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1993).*

10.4 Gas Transportation Contract between the Company and Algonquin dated October
     29, 1999 providing for transportation of approximately 45,000 dekatherms of
     natural  gas per day.  (Filed as Exhibit  10.4 to the Annual  Report of the
     Company on Form 10-K for the year ended December 31, 1999).*

10.5 Agreement between the Company and Maritimes Northeast Pipeline L.L.C. dated
     January  4, 1999  providing  for  transportation  of  approximately  43,200
     dekatherms  of natural  gas per day.  (Filed as Exhibit  10.5 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 2001).*

10.6 Gas Storage Agreement  between the Company and Honeoye Storage  Corporation
     dated October 11, 1985 providing for storage demand of 6,150  dekatherms of
     natural gas per day.  (Filed as Exhibit  10.17 to the Annual  Report of the
     Company on Form 10-K for the year ended December 31, 1985).*

                                       13
<PAGE>


10.7 Firm Gas  Transportation  agreement  between the Company and  Algonquin Gas
     Transmission  Company dated July 27, 2000 providing for  transportation  of
     approximately  15,000  dekatherms of natural gas per day.  Filed as Exhibit
     10.7 to the  Annual  Report of the  Company on Form 10-K for the year ended
     December 31, 1985).*

10.8 Gas Sales Contract between the Company and Esso Resources Canada,  Limited,
     (now  Imperial  Oil of Canada,  Ltd.)  dated as of May 1,  1989.  (Filed as
     Exhibit 10.12 to the Annual Report of the Company on Form 10-K for the year
     ended December 31, 1989).*

10.8.1  Amendment  to the Gas  Sales  Contract  between  the  Company  and  Esso
     Resources  (now Imperial Oil of Canada),  dated as of November 12, 1997 and
     Bridge Agreement dated as of October 23, 1997,  executed pursuant to Master
     Agreement  dated as of  November 1, 1997.  (Filed as Exhibit  10.9.2 to the
     Annual  Report of the Company on Form 10K for the year ended  December  31,
     1998).*

10.9 Gas Sales Agreement between the Company and Boundary Gas, Inc., dated as of
     September 14, 1987; and First Amendment hereto dated as of January 1, 1990;
     Second Amendment  thereto dated as of July 1, 1990; Third Amendment thereto
     dated as of 1991;  Fourth Amendment thereto dated as of June 5, 1991; Fifth
     Amendment thereto dated as of May 4, 1993; Sixth Amendment thereto dated as
     of  September 9, 1993;  Amendment  thereto  dated as of March 8, 1996;  and
     Amendment  thereto dated as of August 20, 1997.  (Filed as Exhibit 10.10 to
     the Annual  Report of the  Company on Form 10K for the year ended  December
     31, 1994.)*

10.10Gas Sales  Agreement  between the Company and Alberta  Northeast  Gas, Ltd.
     dated as of February 7, 1991.  (Filed as Exhibit 10.16 to the Annual Report
     of the Company on Form 10-K for the year ended December 31, 1990).*

10.10.1  Amendments to the Gas Sales  Agreement  between the Company and Alberta
     Northeast Gas, Ltd., dated as of October 1, 1992; May 5, 1993; November 27,
     1995; and March 14, 1996. (Filed as Exhibit 10.12.1 to the Annual Report of
     the Company on Form 10-K for the year ended December 31, 1998).*

10.11Firm Gas  Transportation  Agreement  between the Company and  Iroquois  Gas
     Transmission  System,  L.P. dated as of February 7, 1991. (Filed as Exhibit
     10.17 to the Annual  Report of the  Company on Form 10-K for the year ended
     December 31, 1990).*

10.11.1  Amendment  dated as of November 3, 1998 to the Firm Gas  Transportation
     Agreement  between the Company and Iroquois Gas Transmission  System,  L.P.
     dated as of  February  7,  1991.  (Filed as  Exhibit  10.13.1 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1999).*

10.12Firm Gas  Transportation  Agreement  between the Company and  Tennessee Gas
     Pipeline  Company dated as of February 7, 1991.  (Filed as Exhibit 10.18 to
     the Annual  Report of the Company on Form 10-K for the year ended  December
     31, 1990).*

10.13Gas  Transportation  Contract  between  the  Company  and  Algonquin  dated
     October 29, 1999  providing  for  transportation  of  approximately  29,000
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.15 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1999).*

10.14Gas  Transportation  Contract  between  the  Company  and  Algonquin  dated
     October 29, 1999  providing  for  transportation  of  approximately  96,000
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.16 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1999).*


                                       14
<PAGE>


10.15Gas  Transportation  Contract  between  the  Company  and  Algonquin  dated
     October 29, 1999  providing  for  transportation  of  approximately  20,000
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.17 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1999).*

10.16Gas  Transportation  Contract  between  the  Company  and  Algonquin  dated
     December 1, 1994  providing  for  transportation  of  approximately  20,000
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.19 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1997).*

10.17Gas  Transportation  Contract  between  the  Company  and  Algonquin  dated
     January  1, 1998  providing  for  transportation  of  approximately  27,000
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.20 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1997).*

10.18Gas Transportation  Contract between the Company and CNG Transmission dated
     October  1, 1993  providing  for  transportation  of  approximately  21,000
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.23 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1997).*

10.18.1 Amendment dated as of August 1, 2002 to the Gas Transportation  Contract
     between the Company and CNG  Transmission  dated October 1, 1993  providing
     for a MDQ reduction to 12,978 dekatherms, and extending the term to October
     31, 2005. (Filed as Exhibit 10.18.1 to the Company's Form 10-K for the year
     ended December 31, 2002).*

10.19Gas  Storage  Contract  between  the  Company  and CNG  Transmission  dated
     November 1993 providing for storage demand of 42,000  dekatherms of natural
     gas per day. (Filed as Exhibit 10.24 to the Annual Report of the Company on
     Form 10-K for the year ended December 31, 1997).*

10.20Gas Transportation  Contract between the Company and Tennessee Gas Pipeline
     dated  September 1, 1993  providing  for  transportation  of  approximately
     10,000  dekatherms  of natural gas per day.  (Filed as Exhibit 10.25 to the
     Annual  Report of the Company on Form 10-K for the year ended  December 31,
     1997).*

10.20.1  Amendment  dated  October 31, 2002 to the Gas  Transportation  Contract
     between the Company and  Tennessee  Gas  Pipeline  dated  September 1, 1993
     providing for transportation of approximately  10,533 dekatherms of natural
     gas per day and extending term of the agreement to October 31, 2008. (Filed
     as Exhibit  10.20.1 to the Company's  Form 10-K for the year ended December
     31, 2002).*

10.21Gas Transportation  Contract between the Company and Tennessee Gas Pipeline
     dated September 1, 1993 providing for transportation of approximately 8,600
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.28 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1997).*

10.22Gas Transportation  Contract between the Company and Tennessee Gas Pipeline
     dated  September 1, 1993  providing  for  transportation  of  approximately
     41,000  dekatherms  of natural gas per day.  (Filed as Exhibit 10.29 to the
     Annual  Report of the Company on Form 10-K for the year ended  December 31,
     1997).*

10.22.1  Amendment  dated  October 31, 2002 to the Gas  Transportation  Contract
     between the Company and  Tennessee  Gas  Pipeline  dated  September 1, 1993
     providing for transportation of approximately  41,687 dekatherms of natural
     gas per day and extending term of the agreement to October 31, 2008. (Filed
     as Exhibit  10.22.1 to the Company's  Form 10-K for the year ended December
     31, 2002).*

10.23Gas Storage  Contract  between the Company and Tennessee Gas Pipeline dated
     December 1, 1994  providing  for  storage  demand of  approximately  71,000
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.31 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1997).*


                                       15
<PAGE>


10.23.1  Amendment  dated as of October  31,  2002 to the Gas  Storage  Contract
     between the Company and  Tennessee  Gas  Pipeline  dated  September 1, 1993
     providing for storage demand of approximately  41,687 dekatherms of natural
     gas per day and extending term of the agreement to October 31, 2008. (Filed
     as Exhibit  10.23.1 to the Company's  Form 10-K for the year ended December
     31, 2002).*

10.24Gas Transportation  Contract between the Company and Tennessee Gas Pipeline
     dated  September 1, 1996  providing  for  transportation  of  approximately
     13,000  dekatherms  of natural gas per day.  (Filed as Exhibit 10.32 to the
     Annual  Report of the Company on Form 10-K for the year ended  December 31,
     1997).*

10.24.1  Amendment  dated  as of  October  31,  2002 to the  Gas  Transportation
     Contract  between the Company and Tennessee Gas Pipeline dated September 1,
     1996 providing for  transportation  of approximately  13,027  dekatherms of
     natural  gas per day and  extending  term of the  agreement  to October 31,
     2008.  (Filed as Exhibit  10.24.1 to the  Company's  Form 10-K for the year
     ended December 31, 2002).*

10.25Gas   Transportation   Contract  between  the  Company  and  Texas  Eastern
     Transmission  dated  December  30, 1993  providing  for  transportation  of
     approximately  39,000  dekatherms of natural gas per day. (Filed as Exhibit
     10.33 to the Annual  Report of the  Company on Form 10-K for the year ended
     December 31, 1997).*

10.25.1  Amendment  dated  as of  October  29,  1998 to the  Gas  Transportation
     Contract between the Company and Texas Eastern  Transmission dated December
     30, 1993 providing for transportation of approximately 39,000 dekatherms of
     natural gas per day (Filed as Exhibit  10.27.1 to the Annual  Report of the
     Company on Form 10-K for the year ended December 31, 1999).*

10.26Gas   Transportation   Contract  between  the  Company  and  Texas  Eastern
     Transmission  dated  December  30, 1993  providing  for  transportation  of
     approximately  21,000  dekatherms of natural gas per day. (Filed as Exhibit
     10.34 to the Annual  Report of the  Company on Form 10-K for the year ended
     December 31, 1997).*

10.27Gas   Transportation   Contract  between  the  Company  and  Texas  Eastern
     Transmission  dated  December  30, 1993  providing  for  transportation  of
     approximately  5,000  dekatherms  of  natural  gas per day  (terminated  on
     October  31,  2002).  (Filed as Exhibit  10.35 to the Annual  Report of the
     Company on Form 10-K for the year ended December 31, 1997).*

10.28Gas   Transportation   Contract  between  the  Company  and  Texas  Eastern
     Transmission  dated  October  29,  1999  providing  for  transportation  of
     approximately  29,000  dekatherms of natural gas per day. (Filed as Exhibit
     10.30 to the Annual  Report of the  Company on Form 10-K for the year ended
     December 31, 1999).*

10.29Gas Transportation  Contract between the Company and  Transcontinental  Gas
     Pipeline dated June 1, 1993 providing for  transportation  of approximately
     6,000  dekatherms  of natural gas per day.  (Filed as Exhibit  10.40 to the
     Annual  Report of the Company on Form 10-K for the year ended  December 31,
     1997).*

10.30Gas Transportation  Contract between the Company and Texas Gas Transmission
     dated November 1, 1993 providing for transportation of approximately 13,000
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.41 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1997).*


                                       16
<PAGE>

10.31Gas Transportation  Contract between the Company and Texas Gas Transmission
     dated November 1, 1993 providing for transportation of approximately 13,000
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.41 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1997).*

10.31.1  Amendment  dated  as of  October  31,  2002 to the  Gas  Transportation
     Contract  between the Company and Tennessee Gas Pipeline dated September 1,
     1993 providing for  transportation  of approximately  94,312  dekatherms of
     natural  gas per day and  extending  term of the  agreement  to October 31,
     2008.  (Filed as Exhibit  10.31.1 to the  Company's  Form 10-K for the year
     ended December 31, 2002).*

10.32Agreement  between the Company and Texas Eastern  Transmission  dated as of
     October  29, 1999  providing  for storage  demand of  approximately  68,700
     dekatherms  of natural gas per day.  (Filed as Exhibit  10.35 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1999).*

10.33Agreement  between the Company and Algonquin LNG, Corp. dated as of October
     29, 1999 providing for storage demand of approximately 35,000 dekatherms of
     natural gas per day.  (Filed as Exhibit  10.36 to the Annual  Report of the
     Company on Form 10-K for the year ended December 31, 1999).*

10.34Contract  Restructuring  Agreement  between the Company and  Tennessee  Gas
     Pipeline dated as of August 2, 1999.  (Filed as Exhibit 10.37 to the Annual
     Report of the Company on Form 10-K for the year ended December 31, 1999).*

10.35Redacted Gas Resource Portfolio  Management and Gas Sales Agreement between
     the Company,  Colonial  Gas  Company,  Essex Gas Company and El Paso Energy
     Marketing Company dated as of September 14, 1999, as amended (terminated on
     October  31,  2002).  (Filed as  Exhibit  10.1 to the Form 10-K of  Eastern
     Enterprises for the year ended December 31, 1999.).*

10.36Amended and Restated Lease Agreement  between  Industrial  National Leasing
     Corporation,  Lessor, and Boston Gas Company, Lessee, dated as of April 30,
     1999.  (Filed as Exhibit  10.39 to the Annual Report of the Company on Form
     10-K for the year ended December 31, 1999).*

10.37Precedent  Agreement  between the Company and  Algonquin  Gas  Transmission
     Company  dated  as  of  June  13,  2001  providing  for  transportation  of
     approximately  20,000  dekatherms of natural gas per day. (Filed as Exhibit
     10.40 to the Company's Form 10-K for the year ended December 31, 2001).*

10.38Agreement between the Company and Maritimes  Northeast Gas Pipeline Limited
     Partnership   dated  June  16,  1999   providing  for   transportation   of
     approximately  43,200  dekatherms of natural gas per day. (Filed as Exhibit
     10.41 to the Company's Form 10-K for the year ended December 31, 2001).*

10.39Redacted Gas Resource Portfolio  Management and Gas Sales Agreement between
     the Company,  Colonial  Gas Company and Essex Gas Company and  Entergy-Koch
     Trading,  LP, dated as of October 29, 2002.  (Filed as Exhibit 10.39 to the
     Company's Form 10-K for the year ended December 31,2002).*




                                       17
<PAGE>


31.1 Certification  of the President  and Chief  Operating  Officer  pursuant to
     Section 302 of the  Sarbanes-Oxley Act of 2002 dated August 13, 2003.(Filed
     herewith)

31.2 Certification  of the Senior Vice  President  and Chief  Financial  Officer
     pursuant to Section 302 of the  Sarbanes-Oxley Act of 2002 dated August 13,
     2003. (Filed herewith)

32.1 Certification  of the President  and Chief  Operating  Officer  pursuant to
     Section 906 of the  Sarbanes-Oxley Act of 2002 dated March 28, 2003. (Filed
     herewith)

32.2 Certification  of the Senior Vice  President  and Chief  Financial  Officer
     pursuant to Section 906 of the  Sarbanes-Oxley  Act of 2002 dated March 28,
     2003. (Filed herewith)

32.3 Certification  of the President  and Chief  Operating  Officer  pursuant to
     Section 906 of the Sarbanes-Oxley Act of 2002 dated August 13, 2003. (Filed
     herewith)

32.4 Certification  of the Senior Vice  President  and Chief  Financial  Officer
     pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002 dated August 13,
     2003. (Filed herewith)


Reports on Form 8-K

There were no reports on Form 8-K filed in the Fourth Quarter of 2002.


*  Not filed herewith. In accordance with Rule 12(b)(32) of the General Rules
   and Regulations under the Securities Exchange Act of 1934, reference is made
   to the document previously filed with the Commission.








                                       18
<PAGE>



                                   SIGNATURES

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


                                 Boston Gas Company
                                 D/B/A KeySpan Energy Delivery New England
                                 Registrant


                                 By: /s/NICKOLAS STAVROPOULOS
                                     ------------------------
                                     Nickolas Stavropoulos
                                     Chief Operating Officer
                                     and President





                                 By: /s/JOSEPH F. BODANZA
                                     ---------------------
                                     Joseph F. Bodanza
                                     Senior Vice President and Chief
                                     Accounting Officer


Dated:   August 13, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following  persons on behalf of the  Registrant and
in the capacities indicated on the 13th day of August, 2003.






                       Signature                                  Title
                       ---------                                  -----

                 Nickolas Stavropoulos
                 ---------------------
                 Nickolas Stavropoulos                            Director






                                       19

<PAGE>


                               BOSTON GAS COMPANY
<TABLE>
<CAPTION>
                   INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
            (Information required by Items 8 and 14 (a) of Form 10-K)
<S>                                                                                                                   <C>
  Independent Auditors' Report....................................................................................        F-25
  Report of Independent Public Accountants - 2001 and prior.......................................................        F-26
  Statements of Operations for the Years Ended December 31, 2002 and 2001, and the Periods from
      November 8, 2000 through December 31, 2000 and January 1, 2000 through November 7, 2000.....................        F-2
  Balance Sheets as of December 31, 2002 and 2001.................................................................     F-3 and F-4
  Statements of Retained Earnings (Deficit) and  Statements of Comprehensive Income (Loss)for the
       Years Ended December 31, 2002 and 2001, and the Periods from November 8,
2000 through December 31, 2000 and January 1, 2000 through November 7,  2000 .....................................        F-5
  Statements of Cash Flows for the Years Ended December 31, 2002 and 2001, and the Periods
        from November 8, 2000 through December 31, 2000 and January 1, 2000 through
        November 7, 2000..........................................................................................         F-6
 Notes to Financial Statements....................................................................................     F-7 to F-24
 Interim Financial Information for the Two years Ended December 31, 2002 (unaudited)..............................         F-27
 Schedule for the Years Ended December 31, 2002 and 2001, and the Periods from November 8,
        2000 through December 31, 2000 and January 1, 2000 through November 7, 2000:
            Schedule II--Valuation and Qualifying Accounts.........................................................        F-28

Schedules other than that listed above have been omitted as the information has
been included in the financial statements and related notes or is not applicable
or required.
</TABLE>








                                       F-1
<PAGE>

<TABLE>
<CAPTION>
                                                        BOSTON GAS COMPANY
                                                     STATEMENTS OF OPERATIONS
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                              Period from         Period from
                                                                                               November 8,         January 1,
                                                            Year Ended December 31,           2000 through         2000 through
(In Thousands of Dollars)                                  2002                2001         December 31, 2000    November 7, 2000
--------------------------------------------------------------------------------------------------------------------------------
                                                                                                                 Predecessor
<S>                                                       <C>                  <C>                  <C>                <C>
Operating Revenues                                  $      639,111      $       828,938     $        202,842    $       453,783
     Cost of gas sold                                      345,823              558,683              131,516            247,548
                                              --------------------- --------------------  -------------------  -----------------
    Operating Margin                                       293,288              270,255               71,326            206,235

Operating Expenses:
    Operations and maintenance                             154,095              156,956               25,259            123,667
    Depreciation and amortization                           56,203               52,261               10,745             39,515
    Amortization of goodwill                                     -               19,439                3,226                  -
    Operating taxes                                         17,401               23,570                4,557             18,918
    Merger related expenses                                      -                    -                  101             23,347
                                              --------------------- --------------------  -------------------  -----------------
Total Operating Expenses                                   227,699              252,226               43,888            205,447
                                              --------------------- --------------------  -------------------  -----------------
Operating Income                                            65,589               18,029               27,438                788
                                              --------------------- --------------------  -------------------  -----------------
Other Income                                                   258                2,775                  451                719
Interest Expense:
    Long-term debt                                          16,855               16,835                2,806             13,984
    Other, including amortization of
       debt expense                                         50,658               43,867                3,501             (4,017)
    Less-Interest during construction                       (2,501)                (686)                (202)              (704)
                                              --------------------- --------------------  -------------------  -----------------
Total Interest Expense                                      65,012               60,016                6,105              9,263
                                              --------------------- --------------------  -------------------  -----------------
Income Before Income Taxes                                     835              (39,212)              21,784             (7,756)
Income Taxes
     Current                                               (63,870)              26,839                2,707            (21,186)
     Deferred                                               67,179              (35,895)               7,011             17,718
                                              --------------------- --------------------  -------------------  -----------------
Total Income Tax  Expense (Benefit)                          3,309               (9,056)               9,718             (3,468)
                                              --------------------- --------------------  -------------------  -----------------


Net (Loss)Income                                            (2,474)             (30,156)              12,066             (4,288)
Preferred stock dividends                                      975                1,096                  183              1,174
                                              --------------------- --------------------  -------------------  -----------------
Net Income (Loss) applicable for Common Stock       $       (3,449)     $       (31,252)    $         11,883    $        (5,462)
                                              ===================== ====================  ===================  =================

                                        The accompanying notes are an integral part of these financial statements.
</TABLE>

                                       F-2
<PAGE>

                                                              BOSTON GAS COMPANY
                                                                BALANCE SHEETS

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                                          Year Ended December 31,

(In Thousands of Dollars)                                                           2002                           2001
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                       <C>                            <C>
ASSETS
Property:
         Gas plant, at cost                                                              $ 1,194,842                    $ 1,070,610
         Construction in progress                                                             10,415                         27,875
         Less-Accumulated depreciation                                                      (470,556)                      (425,163)
                                                                         ----------------------------  -----------------------------
                                                                                             734,701                        673,322
                                                                         ----------------------------  -----------------------------

Current assets:
         Cash and temporary cash investments                                                   2,168                          3,104
         Accounts receivable                                                                 123,681                         95,393
         Allowance for uncollectible accounts                                                (14,666)                       (14,730)
         Accounts receivable-affiliates                                                        4,195                          8,851
         Accrued utility revenue                                                              66,619                         50,693
         Deferred gas costs                                                                   68,647                         15,670
         Natural Gas and other inventories, at average cost                                   74,549                         79,544
         Material and supplies, at average cost                                                4,754                          3,996
         Prepaid expenses and other                                                              371                            377
                                                                         ----------------------------  -----------------------------
                                                                                             330,318                        242,898
                                                                         ----------------------------  -----------------------------

Other Assets:
         Goodwill                                                                            790,285                        790,285
         Deferred postretirement cost                                                         44,360                         42,585
         Deferred charges and other assets                                                    96,378                         56,261
                                                                         ----------------------------  -----------------------------
                                                                                             931,023                        889,131
                                                                         ----------------------------  -----------------------------

Total Assets                                                                             $ 1,996,042                    $ 1,805,351
------------------------------------------------------------------------------------------------------------------------------------



                                                The accompanying notes are an integral part of these financial statements.
</TABLE>
                                       F-3


<PAGE>


                                                              BOSTON GAS COMPANY
                                                                BALANCE SHEETS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                                                                                         Year Ended December 31,
(In Thousands of Dollars)                                                           2002                         2001
------------------------------------------------------------------------------------------------------------------------------

LIABILITIES AND CAPITALIZATION
<S>                                                                                     <C>                          <C>
Capitalization
                Common stock, $100 par value-authorized and
                outstanding-514,184 shares                                              $ 51,418                     $ 51,418
                Amounts in excess in par value                                           560,575                      360,575
                Accumulated deficit                                                      (22,817)                     (19,368)
                Accumulated other comprehensive income                                    (9,823)                        (692)
                                                                       --------------------------  ---------------------------
                     Total common stockholder's investment                               579,353                      391,933
                Cumulative Preferred stock, $1 par value, liquidation
                preference $25 per share-562,700 and 622,700 shares
                at December 31, 2002 and 2001,
                respectively                                                              13,840                       15,289
                Long-term obligations, less current portion                              222,563                      223,403
                                                                       --------------------------  ---------------------------
Total Capitalization                                                                     815,756                      630,625
                                                                       --------------------------  ---------------------------
                Advance from KeySpan                                                     650,000                      650,000
                                                                       --------------------------  ---------------------------
Total Capitalization and Advance from KeySpan                                          1,465,756                    1,280,625
                                                                       --------------------------  ---------------------------

Commitments and Contingencies(See Note 6)

Current Liabilities
                Current portion of long-term obligations                                     840                          586
                Notes payable utility pool                                                67,174                      147,350
                Notes payable utility pool - gas inventory financing                      83,907                       85,401
                Accounts payable and affiliates                                          131,380                       99,608
                Accrued taxes                                                              4,495                        5,740
                Accrued income taxes                                                      (6,747)                      (2,432)
                Accrued interest                                                           4,334                       11,377
                Customer deposits                                                          1,563                        1,884
                Other current liabilities                                                      -                          157
                                                                       --------------------------  ---------------------------
                                                                                         286,946                      349,671
                                                                       --------------------------  ---------------------------

Deferred Credits and Other Liabilities
                Deferred income tax                                                      141,408                       73,609
                Unamortized investment tax credits                                         1,714                        2,556
                Postretirement benefits obligation                                        53,747                       50,901
                Environmental liability                                                   28,831                       31,878
                Other                                                                     17,640                       16,111
                                                                       --------------------------  ---------------------------
                                                                                         243,340                      175,055
                                                                       --------------------------  ---------------------------
Total Capitalization and Liabilities                                                 $ 1,996,042                  $ 1,805,351
------------------------------------------------------------------------------------------------------------------------------



                                                The accompanying notes are an integral part of these financial statements.
</TABLE>
                                       F-4


<PAGE>


<TABLE>
<CAPTION>
                                                           BOSTON GAS COMPANY
                                              STATEMENTS OF RETAINED EARNINGS (DEFICIT)
----------------------------------------------------------------------------------------------------------------------------------
                                                                                            Period from            Period from
                                                                                            November 8,           January 1, 2000
                                                    Year Ended December 31,                2000 through              through
(In Thousands of Dollars)                        2002                    2001            December 31, 2000       November 7, 2000
----------------------------------------------------------------------------------------------------------------------------------
                                                                                                                     Predecessor
<S>                                              <C>                    <C>                      <C>                     <C>
Balance at beginning of period                   $ (19,368)             $ 11,883                $      -                $ 189,517
    Net (loss) income                               (2,474)              (30,155)                 12,066                   (4,288)
    Preferred stock dividend                          (975)               (1,096)                   (183)                  (1,174)
    Common stock dividend                                -                     -                       -                  (22,496)
----------------------------------------------------------------------------------------------------------------------------------
Balance at end of period                        $  (22,817)            $ (19,368)               $ 11,883                $ 161,559
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
                                                          BOSTON GAS COMPANY
                                               STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
------------------------------------------------------------------------------------------------------------------------------------
                                                                                               Period from            Period from
                                                                                               November 8,          January 1, 2000
                                                          Year Ended December 31,             2000 through              through
(In Thousands of Dollars)                               2002                    2001        December 31, 2000       November 7, 2000
------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                         Predecessor
<S>                                                   <C>                   <C>                    <C>                      <C>
Net (loss) income                                     $ (2,474)            $ (30,155)              $ 12,066                 $(4,288)
------------------------------------------------------------------------------------------------------------------------------------
    Other Comprehensive income (loss) net of tax
    Accrued unfunded pension obligation                 (9,374)                 (692)                     -                       -
------------------------------------------------------------------------------------------------------------------------------------
Other Comprehensive income (loss) net of tax         $  (9,374)            $    (692)              $      -                 $     -
------------------------------------------------------------------------------------------------------------------------------------
Comprehensive (loss) income                          $ (11,848)            $ (30,847)              $ 12,066                 $(4,288)
------------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
    Accrued unfunded pension obligation                 (5,047)                 (373)                     -                       -
------------------------------------------------------------------------------------------------------------------------------------
Total tax (benefit)                                  $  (5,047)            $    (373)              $      -                 $     -
------------------------------------------------------------------------------------------------------------------------------------










                                        The accompanying notes are an integral part of these financial statements.
</TABLE>
                                       F-5


<PAGE>

<TABLE>
<CAPTION>
                                                                    STATEMENTS OF CASH FLOWS
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Period from          Period from
                                                                                                 November 8,           January 1,
                                                           Year Ended         Year Ended        2000 through            2000 through
(In Thousands of Dollars)                               December 31, 2002  December 31, 2001  December 31, 2000     November 7, 2000
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                                                      Predecessor
<S>                                                             <C>              <C>                <C>               <C>
Operating Activities
Net (loss) income                                              $ (2,474)         $ (30,155)         $ 12,066          $ (4,288)
Adjustments to reconcile net income to net
  cash provided by (used in) operating activities
  Depreciation and amortization                                  56,203             71,700            13,971            39,515
  Deferred income tax                                            67,179            (35,895)            7,011            17,718
Changes in assets and liabilities
  Accounts receivable and affiliates                            (23,637)            10,812           (61,736)           46,483
  Accrued utility revenue                                       (15,926)            21,130           (16,287)           14,029
  Natural Gas and other inventories                               4,237            (22,396)           18,987           (31,560)
  Deferred gas costs                                            (52,977)            61,995           (51,225)          (28,066)
  Accounts payable and affiliates                               (31,772)            (5,735)           25,060            32,314
  Accrued income taxes                                           (5,560)            16,178             5,249           (20,495)
  Other                                                           6,200             (2,929)            3,237             4,056
                                                        ----------------   ----------------  ----------------  ----------------
Net Cash Provided by (Used in)  Operating Activities              1,473             84,705           (43,667)           69,706
                                                        ----------------   ----------------  ----------------  ----------------
Investing Activities
Capital expenditures                                           (110,360)          (111,735)          (21,802)          (52,958)
Net cost of removal                                              (7,904)            (6,834)           (1,272)           (4,628)
                                                        ----------------   ----------------  ----------------  ----------------
Net Cash Used in Investing Activities                          (118,264)          (118,569)          (23,074)          (57,586)
                                                        ----------------   ----------------  ----------------  ----------------
Financing Activities
Changes in advance from KeySpan                                                     50,000
Capital Contribution from KNE LLC                               200,000
Changes in notes payable - utility money pool                   (80,176)            32,507            54,843             8,800
Changes in gas inventory financing - utility money pool          (1,494)             3,094            13,719            14,568
Redemption of preferred stock                                    (1,500)            (1,500)                             (9,933)
Dividends paid on common and preferred stock                       (975)           (51,096)             (183)          (23,670)
Other                                                                                   47                 4               217
                                                        ----------------   ----------------  ----------------  ----------------
Net Cash Provided by (Used in) Financing Activities             115,855             33,052            68,383           (10,018)
                                                        ----------------   ----------------  ----------------  ----------------
Net (Decrease) or Increase in Cash and Cash Equivalents        $   (936)         $    (812)         $  1,642          $  2,102
                                                        ================   ================  ================  ================
Cash and Cash Equivalents at Beginning of Period                  3,104              3,916             2,274               172
                                                        ----------------   ----------------  ----------------  ----------------
Cash and Cash Equivalents at End of Period                     $  2,168          $   3,104          $  3,916          $  2,274
                                                        ================   ================  ================  ================
Interest Paid                                                  $ 79,813          $  75,438          $ 18,255          $      -
Income Tax Paid                                                $  1,310          $   2,489          $ (1,718)         $    115
-------------------------------------------------------------------------------------------------------------------------------

                                        The accompanying notes are an integral part of these financial statements.
</TABLE>
                                       F-6

<PAGE>


                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS

(1)   Accounting Policies

General

Boston Gas Company D/B/A KeySpan Energy Delivery New England (referred to herein
as the "Company",  "we" "us and "our") is a gas distribution  company engaged in
the  transportation  and sale of  natural  gas to  residential,  commercial  and
industrial  customers.  The Company's service  territory  includes Boston and 73
other  communities  in  eastern  and  central  Massachusetts.  The  Company is a
wholly-owned  subsidiary of KeySpan New England LLC ("KNE LLC")  (Formerly known
as Eastern  Enterprises)  and an  indirect  wholly-owned  subsidiary  of KeySpan
Corporation  ("KeySpan"),  a registered holding company under the Public Utility
Holding Company Act ("PUHCA") of 1935, as amended.

Basis of Presentation

The accounting  records are maintained in accordance  with the Uniform System of
Accounts prescribed by the Massachusetts  Department of  Telecommunications  and
Energy (the  "Department").  The accounting  policies of the Company  conform to
generally  accepted  accounting  principles  and  reflect  the  effects  of  the
rate-making  process  in  accordance  with  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 on the Balance
Sheet, respectively.

The  financial   statements   include  the  accounts  of  the  Company  and  its
wholly-owned subsidiary,  Massachusetts LNG Incorporated,  which became inactive
in 1999.

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.

Certain  reclassifications have been made to the prior year financial statements
to conform to the current year presentation.

Merger and Goodwill

On November 8, 2000,  KeySpan  acquired  all of the common  stock of KNE LLC for
$64.56 per share in cash. The  transaction  was accounted for using the purchase
method of accounting for business combinations. The purchase price was allocated
to the net assets acquired of KNE LLC and its subsidiaries based upon their fair
value. The historical cost basis of the Company'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.  Under "push-down"  accounting,  the
excess of the  purchase  price over the fair value of the  Company's  net assets
acquired,  or goodwill,  of approximately  $774 million was recorded as an asset
and was being  amortized  over a period of 40 years (see below).  The  push-down
accounting  resulted in an increase in equity of $170 million and the  recording
of a $600 million advance from KeySpan. An additional $38.7 million was recorded
as goodwill in finalizing the purchase price allocation,  of which $36.2 million
was an addition to equity.


                                       F-7

<PAGE>

                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS

(1) Accounting Policies (Continued)

On January 1, 2002, the Company adopted SFAS 142 "Goodwill and Other  Intangible
Assets".  Under SFAS 142, among other things,  goodwill is no longer required to
be amortized and is to be tested for impairment at least  annually.  The initial
impairment test was to be performed within six months of adopting SFAS 142 using
a discounted  cash flow  method,  compared to an  undiscounted  cash flow method
allowed under a previous standard. Any amounts impaired using data as of January
1, 2002,  was to be recorded as a "Cumulative  Effect of an Accounting  Change".
Any amounts impaired using data after the initial adoption date will be recorded
as an operating  expense.  During the second  quarter of 2002,  we completed our
initial  impairment  analysis for the Company and determined  that no impairment
existed.  Also,  in the  fourth  quarter of 2002,  we updated  our review of the
carrying value of goodwill compared to the fair value of the assets by reporting
unit and determined that no impairment existed.

As required by SFAS 142, below is a reconciliation of reported net income (loss)
applicable  for common  stockholders  for the years ended  December 31, 2002 and
2001 and the periods from November 8, 2000 through December 31, 2000 and January
1, 2000 through  November 7, 2000 and pro-forma net income (loss),  for the same
periods, adjusted for the discontinuance of goodwill amortization.
<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------------------------------------------
                                                                                               Period from          Period from
                                                                                               November 8,           January 1,
                                                                Year Ended December 31,        2000 through         2000 through
(In Thousands of Dollars)                                        2002             2001      December 31, 2000     November 7, 2000
------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                        Predecessor
<S>                                                           <C>             <C>               <C>                   <C>
Net income (loss) applicable for common stock                $ (3,449)       $ (31,251)        $ 11,883              $ (5,462)
   Add back: goodwill amortization                                  -           19,439            3,226                     -
------------------------------------------------------------------------------------------------------------------------------------
Adjusted net income (loss) applicable for common stock       $ (3,449)       $ (11,812)        $ 15,109              $ (5,462)
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

Recent Accounting Pronouncements

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

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


                                      F-8


<PAGE>


                               BOSTON GAS COMPANY
                          NOTES TO FINANCIAL STATEMENTS

(1) Accounting Policies (Continued)

We have  completed  our  assessment  of SFAS 143.  Our asset  base is  primarily
composed  of  storage,  and  distribution  assets  which we  believe  operate in
perpetuity and,  therefore,  have  indeterminate  cash flow  estimates.  A legal
obligation may be construed to exist due to certain safety requirements at final
abandonment.  In  addition,  a legal  obligation  may be construed to exist with
respect to our LNG storage tanks due to clean up responsibilities upon cessation
of use.  Since  that  exposure  is in  perpetuity  and  cannot be  measured,  no
liability will be recorded. Our asset retirement obligation will be re-evaluated
annually.

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

In June of 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with
Exit or Disposal Activities".  This Statement addresses financial accounting and
reporting for costs  associated  with exit or disposal  activities and nullifies
Emerging Issues Task Force ("EITF") Issue No. 94-3,  "Liability  recognition for
Certain Employee Termination benefits and Other Costs to Exit an Activity". This
Statement is effective for exit or disposal activities  initiated after December
31, 2002, with early application encouraged.

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

In  January  2003,  the FASB  issued  FASB  Interpretation  No.  46 ("FIN  46"),
"Consolidation of Variable Interest Entities,  an Interpretation of ARB No. 51."
FIN 46 requires  certain  variable  interest  entities to be consolidated by the
primary  beneficiary of the entity if the equity  investors in the entity do not
have the  characteristics  of a  controlling  financial  interest or do not have
sufficient  equity at risk for the  entity to  finance  its  activities  without
additional  subordinated  financial  support  from  other  parties.  FIN  46  is
effective  for all new  variable  interest  entities  created or acquired  after
January 31, 2003. For variable  interest  entities  created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period  beginning  after June 15, 2003. At the present time, we do not
have any arrangements with variable interest entities.

                                       F-9


<PAGE>


                               BOSTON GAS COMPANY
                          NOTES TO FINANCIAL STATEMENTS

(1) Accounting Policies (Continued)

Regulation

The  Company  is  regulated  as to rates,  accounting  and other  matters by the
Department.  Therefore,  we account for the economic  effects of  regulation  in
accordance  with the  provisions of SFAS 71. In the event that we determine that
the Company no longer meets the criteria for following  SFAS 71, the  accounting
impact would be an  extraordinary,  non-cash  charge to  operations of an amount
that could be material.  Management  believes that this amount would approximate
$49.0 million,  net of taxes, as of December 31, 2002.  Criteria that gives rise
to the  discontinuance  of SFAS  71  include  (1)  increasing  competition  that
restricts  our ability to establish  prices to recover  specific  costs or (2) a
significant  change in the manner in which rates are set by regulators.  We have
reviewed these criteria and believe that the continued application of SFAS 71 is
appropriate.

Regulatory  assets have been established that represent  probable future revenue
to the  Company  associated  with  certain  costs  that will be  recovered  from
customers  through the rate-making  process.  Regulatory  liabilities  represent
probable  future  reductions in revenues  associated with amounts that are to be
credited to customers through the rate-making process.

The  following  regulatory  assets were  reflected  on the  balance  sheet as of
December 31:

----------------------------------------------------------------------------
In Thousands of Dollars                              2002              2001
----------------------------------------------------------------------------

Post-retirement benefit costs                    $ 44,360          $ 42,585
Environmental costs                                36,939            35,917
----------------------------------------------------------------------------
                                                 $ 81,299          $ 78,502
----------------------------------------------------------------------------


Environmental  costs are  included in Deferred  Charges and Other  Assets on the
Balance Sheet. Regulatory liabilities, primarily relating to income taxes, total
approximately  $5.9  million  and $6.8  million at  December  31, 2002 and 2001,
respectively.  These  amounts are included in Other  Deferred  Credits and Other
Liabilities on the Balance Sheet.

As of December 31, 2002, all of our regulatory  assets and liabilities for which
cash  expenditures  have been made or cash has been  received  are  reflected in
rates  charged or credited to  customers.  We estimate that full recovery of our
regulatory assets will not exceed 20 years. For additional information regarding
deferred income taxes,  post-retirement  benefit costs and environmental  costs,
see Notes 2, 5 and 9, respectively.

Gas Operating Revenues

Customers are billed 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.







                                      F-10


<PAGE>


                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS

(1) Accounting Policies (Continued)


Cost of Gas Adjustment Clause and Deferred Gas Costs

The cost of gas adjustment clause ("CGAC") requires us to semiannually, or based
on certain criteria  monthly,  adjust rates for firm gas sales in order to track
changes in the cost of gas distributed,  with an annual adjustment of subsequent
rates made for any over or under recovery of actual costs incurred. As a result,
the cost of firm gas that has been  distributed  to customers but is unbilled at
the end of a period  is  deferred  to the  period  in which the gas is billed to
customers.  We recover the gas cost portion of bad debt  write-offs  through the
CGAC. In addition,  through a local distribution  adjustment clause ("LDAC"), we
are  allowed  to  recover  the  amortization  of  environmental  response  costs
associated with former  manufactured  gas plant ("MGP") sites,  costs related to
the our various conservation and load management  programs,  and other specified
costs from our firm sales and transportation customers.

Property and Depreciation

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.

Depreciation  is provided at rates  designed to amortize the cost of depreciable
property,  plant and equipment over their estimated  remaining useful lives. The
composite   depreciation  rate,   expressed  as  a  percentage  of  the  average
depreciable   property  in  service,  is  approximately  5.0%  for  all  periods
presented.  Amortization is provided on intangible assets, principally software,
over the estimated useful life of these assets.

Accumulated  depreciation is charged with original cost and the cost of removal,
less salvage value, of units retired.  Expenditures for repairs, upkeep of units
of property and renewal of minor items of property replaced independently of the
unit of which they are a part are charged to maintenance expense as incurred.

(2)   Income Taxes

For 2002, the Company will file a  consolidated  income tax return with KeySpan.
We also filed a consolidated return with KeySpan for the year ended 2001 and the
period from  November 8, 2000 through  December 31, 2000.  Under the KeySpan tax
sharing  agreement,  the  allocation of the realized tax liability or benefit on
the federal  consolidated  income tax return will be based upon separate  return
contributions  of each  company in the  consolidated  group to the  consolidated
taxable income or loss. For the period January 1, 2000 through November 7, 2000,
we filed a consolidated federal income tax return with KNE LLC. For this period,
we followed a policy,  established  for the group, of providing for income taxes
payable on a separate company basis.

Our effective  income tax rate was 396% in 2002,  23.1% for 2001,  and 44.6% for
the period from November 8 through  December 31, 2000,  and 44.7% for the period
from January 1 through November 7, 2000. The majority of the differences between
the effective  rate and the federal  income tax rate of 35% are primarily due to
state income taxes for each of the periods as well as the  non-deductibility  of
goodwill amortization for the periods from November 8, 2000 through December 31,
2001. In 2002, the effective  income tax rate of 396% is primarily a function of
$4.4 million in state taxes,  net of a federal tax benefit,  on only $895,000 of
pre-tax  book  income.  The state tax  expense is high in  relation  to the book
income due to deductions primarily related to pension contributions and deferred
gas costs,  which resulted in the Company generating a current state tax benefit
and a  deferred  state  tax  expense.  Massachusetts  does not  allow  regulated
utilities  to utilize  state net  operating  losses.  Therefore,  the Company is
unable to offset its deferred  tax expense  with its current  state tax benefit,
resulting in the disproportionate expense for the current year.


                                      F-11


<PAGE>


                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS

(2) Income Taxes (Continued)

      A summary of the provision (benefit) for income taxes is as follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                                                                               Period from          Period from
                                                                                               November 8,           January 1,
                                                      Year Ended December 31,                 2000 through            2000 through
(In Thousands of Dollars)                            2002                2001               December 31, 2000     November 7, 2000
----------------------------------------------------------------------------------------------------------------------------------
                                                                                                                       Predecessor
<S>                                               <C>                 <C>                        <C>                     <C>
Current-
    Federal                                      $ (60,391)           $ 22,378                   $ 2,258                $ (17,695)
    State                                           (3,479)              4,461                       449                   (3,491)
                                          -----------------  ------------------  ------------------------  -----------------------
       Total current provision(benefit)            (63,870)             26,839                     2,707                  (21,186)
Deferred-
   Federal                                          56,972             (30,198)                    5,835                   14,713
   State                                            10,207              (5,697)                    1,176                    3,005
                                          -----------------  ------------------  ------------------------  -----------------------
       Total deferred provision(benefit)            67,179             (35,895)                    7,011                   17,718

Total provision(benefit)  for income taxes         $ 3,309            $ (9,056)                  $ 9,718                 $ (3,468)
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


Deferred  tax  assets  and   liabilities  are  recognized  for  the  future  tax
consequences   attributable  to  differences  between  the  financial  statement
carrying  amounts of existing assets and  liabilities  and their  respective tax
bases.  Deferred tax assets and liabilities are measured using enacted tax rates
expected  to apply to  taxable  income  in the  years in which  those  temporary
differences are expected to be recovered or settled.

At December 31, 2002,  the Company had a  regulatory  tax  liability of $879,000
which  represents  the tax benefit of unamortized  investment tax credits.  This
benefit is being passed back to customers over the lives of property giving rise
to the investment credit. We also had a regulatory  liability of $5.0 million at
December 31, 2002, for excess  deferred taxes being returned to customers over a
30-year period pursuant to a 1988 rate order.

For  income  tax  purposes,   we  use  accelerated   depreciation   and  shorter
depreciation  lives, as permitted by the Internal Revenue Code. Deferred federal
and state taxes are  provided for the tax effects of all  temporary  differences
between  financial  reporting and taxable  income.  Significant  items making up
deferred  tax  assets  and  liabilities  at  December  31,  2002 and 2001 are as
follows:










                                      F-12


<PAGE>



                                                         BOSTON GAS COMPANY

                                                   NOTES TO FINANCIAL STATEMENTS

(2) Income Taxes (Continued)
<TABLE>
<CAPTION>
                                                                    Year Ended                  Year Ended
In Thousands of Dollars                                         December 31, 2002            December 31, 2001
-------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>                        <C>
Assets:
    Regulatory liabilities                                                   $   2,381                   $   2,718
    Other                                                                       35,965                      31,784
                                                            ---------------------------  --------------------------
          Total deferred tax assets                                             38,346                      34,502
                                                            ---------------------------  --------------------------
Liabilities:
    Accelerated depreciation                                                   (97,737)                    (85,333)
    Deferred gas costs                                                         (46,884)                      2,604
    Other                                                                      (38,916)                    (19,752)
                                                            ---------------------------  --------------------------
          Total deferred tax liabilities                                      (183,537)                   (102,481)
                                                            ---------------------------  --------------------------

-------------------------------------------------------------------------------------------------------------------
          Total net deferred taxes                                          $ (145,191)                  $ (67,979)
-------------------------------------------------------------------------------------------------------------------

Deferred income taxes are reflected in the balance sheet as follows:
    Accrued income taxes (current deferred)                                 $   (3,783)                  $   5,630
    Deferred income taxes (long-term)                                         (141,408)                    (73,609)
                                                            ---------------------------  --------------------------
                                                                            $ (145,191)                  $ (67,979)
                                                            ===========================  ==========================
</TABLE>

Investment tax credits are deferred and credited to income over the lives of the
property  giving rise to such  credits.  The credits to income for both 2002 and
2001 were $842,000, $140,000 for the period from November 8 through December 31,
2000 and $702,000 for the period from January 1 through November 7, 2000.

(3)   Debt

Long-term Obligations

The following table provides information on long-term obligations as of December
31:
<TABLE>
<CAPTION>
(In Thousands of Dollars)                                                         2002                        2001
-----------------------------------------------------------------------------------------------------------------------


<S>                                                                               <C>                         <C>
 8.33%--9.75%, Medium-Term Notes Series A, due 2005--2022                        $ 100,000                   $ 100,000
 6.93%--8.50%, Medium-Term Notes, Series B, due 2006--2024                          50,000                      50,000
 6.80%--7.25%, Medium-Term Notes, Series C, due 2012--2025                          60,000                      60,000
 Capital lease obligations (Note 6)                                                 13,403                      13,989
 Less current portion                                                                 (840)                       (586)

-----------------------------------------------------------------------------------------------------------------------
                                                                                 $ 222,563                   $ 223,403
-----------------------------------------------------------------------------------------------------------------------
</TABLE>



                                      F-13


<PAGE>


                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS

(3) Debt (Continued)

There are no sinking  fund  requirements  for the next two years  related to the
$210 million of Medium-Term  Notes and none are callable  prior to maturity.  In
2005,  $15 million of 8.875%  Medium-Term  Notes Series A, mature.  In 2006, $12
million of 8.09% Medium-Term Notes Series B, mature.

Annual  maturities  of  capital  lease  obligations  for 2003  through  2007 are
$840,000, $891,000, $945,000, $1.0 million and $1.06 million, respectively.

Utility Money Pool Borrowings

Financing  for the  Company  for  working  capital  and gas  inventory  needs is
obtained  through the  Company's  participation  in a utility  money  pool.  The
utility money pool is administered by KeySpan  Corporate  Services  ("KCS").  At
December 31, 2002, the Company had  outstanding  borrowings of $67.2 million and
$83.9  million for working  capital and gas  inventory,  respectively.  Interest
charged on  outstanding  borrowings is generally  equal to KeySpan's  short term
borrowing rate, plus a proportional share of the  administrative  costs incurred
in obtaining the required funds.  All costs related to gas inventory  borrowings
are  recoverable  from customers  through the CGAC. The average annual  interest
rate on these borrowings for 2002 was 2.9%.

Advance from KeySpan

As part of the  acquisition by KeySpan in November 2000, the Company  recorded a
$600 million advance payable to KeySpan.  During 2001, an additional $50 million
was advanced from Keyspan.  Interest charges equal interest  incurred by KeySpan
on debt  borrowings  issued by KeySpan.  The  weighted-average  interest rate on
these  borrowings for 2002 is 7.78 %. Issuance expense is charged to the Company
from KeySpan equal to the  amortization  of actual  issuance  costs  incurred by
KeySpan on its debt borrowings.  KeySpan  amortizes these costs over the life of
the related KeySpan borrowings.

(4)   Preferred Stock

The Company has outstanding 562,700 shares of 6.421% Cumulative Preferred Stock,
which is non-voting and has a liquidation  value of $25 per share. The preferred
stock  requires 5% annual  sinking fund payments  beginning on September 1, 1999
with a final  redemption  on September 1, 2018.  At the  Company's  option,  the
annual  sinking fund payment may be  increased  to 10%. The  preferred  stock is
callable at par in September 2003. The Company redeemed 60,000 shares,  or 5% at
$25 per share, on both September 1, 2002 and September 3, 2001.

(5)   Retiree Benefits

The Company provides  post-retirement  benefits,  including pension ("pension"),
medical  and  life  insurance   (collectively   "health   care")   benefits  for
substantially all of its employees.  The plan is contributory for retirees, with
respect to medical benefits and  noncontributory  with respect to life insurance
benefits.




                                      F-14


<PAGE>

                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS


(5) Retiree Benefits (Continued)

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

Pension  benefits  for  salaried  employees  are  based on  salary  and years of
service,  while  pension  benefits for union  employees  are based on negotiated
benefits and years of service.  Employees hired before 1993 who are participants
in the pension  benefit plans become  eligible for  post-retirement  health care
benefits if they reach retirement age while working for the Company. The funding
of these pension  benefit plans is in accordance  with the  requirements  of the
plans and,  where  applicable,  in  sufficient  amounts to satisfy the  "Minimum
Funding Standards" of the Employee Retirement Income Security Act ("ERISA").

Effective  December 31, 2002,  KeySpan merged our qualified  pension plans, with
other KeySpan pension plans, into a consolidated  Pension Plan (thus forming The
KeySpan  Retirement  Plan).  Thus, for 2002, the pension  disclosures  presented
below  represent  the  portion of The KeySpan  Retirement  Plan as it relates to
direct employees of the Company,  with the exception of management  employees of
an affiliate, Essex Gas Company, who are included in this plan and for which the
benefit  obligation  attributed to them  approximates  3.8% of the total benefit
obligation at December 31, 2002.  Prior to 2002,  plan  information  was for the
Company's  separate  pension  plans.  The health care plans have not been merged
with our KeySpan plans and therefore,  continue to remain  separate plans of the
Company.

























                                      F-15


<PAGE>

                                                        BOSTON GAS COMPANY

                                                   NOTES TO FINANCIAL STATEMENTS


      (5)   Retiree Benefits (Continued)

The net cost for these plans were charged to expense as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
                                                                                           Period from          Period from
                                                                                           November 8,           January 1,
Pensions                                                 Year Ended December 31,          2000 through            2000 through
(In Thousands of Dollars)                                  2002            2001         December 31, 2000     November 7, 2000
------------------------------------------------------------------------------------------------------------------------------
                                                                                                                   Predecessor
<S>                                                      <C>              <C>              <C>                 <C>
Service cost - benefits earned during the period         $ 3,536        $    2,964        $    410            $   2,272
Interest cost on benefit obligation                       11,941            10,690           1,835                8,170
Expected return on plan assets                           (12,330)          (12,701)         (2,176)             (10,698)
Amortization of prior service cost                           945                 -               -                1,090
Amortization of transitional obligation                        -                 -               -                  186
Amortization of net actuarial (gain)/loss                  1,918                60               -                 (821)
------------------------------------------------------------------------------------------------------------------------------
Total pension cost                                       $ 6,010        $    1,013        $     69            $     199
------------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
                                                                                           Period from          Period from
                                                                                           November 8,           January 1,
Health Care                                             Year Ended December 31,           2000 through            2000 through
(In Thousands of Dollars)                                2002            2001           December 31, 2000     November 7, 2000
-------------------------------------------------------------------------------------------------------------------------------
                                                                                                                   Predecessor
<S>                                                   <C>              <C>               <C>                      <C>
Service cost-benefits earned during the period       $ 1,386        $    1,358         $    131                  $    624
Interest cost on  benefit obligation                   6,683             6,687            1,110                     4,736
Expected return on plan assets                        (2,193)           (2,349)            (405)                   (1,787)
Amortization of prior service cost                        12                 -                -                      (882)
Amortization of net actuarial (gain)/loss                895               636                -                      (726)
Regulatory deferral                                        -                 -              486                     4,646
-------------------------------------------------------------------------------------------------------------------------------
Total health care cost                               $ 6,783        $    6,332         $  1,322                  $  6,611
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>







                                      F-16



<PAGE>


                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS


(5) Retiree Benefits (Continued)

The following table sets forth the change in benefit  obligation and plan assets
and reconciliation of funded status of our pension plans and amounts recorded on
the balance sheet as of December 31, 2002, and December 31, 2001:

--------------------------------------------------------------------------------
Pensions                                                     December 31,
(In Thousands of Dollars)                                 2002          2001
--------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period             $ 162,953       $ 157,285
Service cost                                              3,536           2,964
Interest cost                                            11,941          10,690
Amendments                                                7,452           4,419
Actuarial gain (loss)                                     9,883          (8,403)
Benefits paid                                            (8,859)         (4,002)
--------------------------------------------------------------------------------
Benefit obligation at end of period                     186,906         162,953
--------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period        150,240         153,328
Actual return on plan assets                            (30,322)         (8,968)
Employer contributions                                   44,460          19,000
Adjustment                                                    -          (4,717)
Benefits paid                                            (8,858)         (8,403)
--------------------------------------------------------------------------------
Fair value of plan assets at end of period              155,520         150,240
--------------------------------------------------------------------------------
Reconciliation of funded Status:
Funded status                                           (31,386)        (12,713)
Unrecognized actuarial loss                              75,938          33,085
Unrecognized prior service cost                          10,030           4,419
--------------------------------------------------------------------------------
Net prepaid pension cost reflected on balance sheet    $ 54,582       $  24,791
--------------------------------------------------------------------------------

Prepaid pension costs are reflected in Deferred Charges and Other Assets on the
Balance Sheet.











                                      F-17


<PAGE>


                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS

(5) Retiree Benefits (Continued)

The following table sets forth the change in benefit  obligation and plan assets
and  reconciliation  of  funded  status of our  health  care  plans and  amounts
recorded on the balance sheet as of December 31, 2002 and December 31, 2001:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------
Health Care                                                                              December 31,
(In Thousands of Dollars)                                                          2002                2001
----------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>                  <C>
Change in benefit obligation:
Benefit obligation at beginning of period                                      $ 100,877           $  87,440
Service cost                                                                       1,386               1,358
Interest cost                                                                      6,683               6,686
Amendments                                                                            87                  21
Plan participants contributions                                                       27                   -
Actuarial gain (loss)                                                              5,106              11,860
Benefits paid                                                                     (5,421)             (6,488)
----------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                                              108,745             100,877
----------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period                                  27,695              27,432
Actual return on plan assets                                                      (4,723)                783
Employer contributions                                                             3,910               5,947
Plan participants contributions                                                       27                  21
Benefits paid                                                                     (5,421)             (6,488)
----------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                                        21,488              27,695
----------------------------------------------------------------------------------------------------------------
Reconciliation of funded Status:
Funded status                                                                    (87,257)            (73,182)
Unrecognized actuarial loss                                                       34,827              22,577
Unrecognized prior service cost                                                       75                   -
----------------------------------------------------------------------------------------------------------------
Net (accrued) health care cost reflected on balance sheet                      $ (52,355)          $ (50,605)
----------------------------------------------------------------------------------------------------------------
</TABLE>


Accrued  health care costs are  primarily  reflected in  Postretirement  Benefit
Obligation on the Balance Sheet.

To fund health care benefits under its  collective  bargaining  agreements,  the
Company maintains a Voluntary Employee Beneficiary Association ("VEBA") Trust to
which it makes  contributions  from time to time.  Pension  and health care plan
assets are invested principally in common stock and fixed income assets.










                                      F-18


<PAGE>


                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS

(5) Retiree Benefits (Continued)

Following are the weighted-average  assumptions used in developing the projected
and accumulated benefit obligations:

--------------------------------------------------------------------------------
                                                  Year Ended December 31,
(In Thousands of Dollars)                      2002         2001        2000
--------------------------------------------------------------------------------
Assumptions:
Obligation discount                            6.75%        7.00%       7.00%
Asset return                                   8.50%        8.50%       8.50%
Average annual increase in compensation        4.00%        4.00%       5.00%

Health care inflation trend                 5.0-9.0%    5.0-10.0%       8.00%
--------------------------------------------------------------------------------



The health care inflation rate for 2003 is assumed to be 9%. The rate is assumed
to  decrease  gradually  to 5% in 2009 and  remain at that level  thereafter.  A
one-percentage-point  increase or decrease in the assumed health care trend rate
for 2002 would have the following effects:

                                                     One-               One-
                                                  Percentage         Percentage
                                                    Point              Point
(In Thousands of Dollars)                          Increase           Decrease
-------------------------------------------------------------------------------

Net periodic healthcare expense                     $   606        $   (554)
Postretirement benefit obligation                   $ 7,474        $ (6,979)
-------------------------------------------------------------------------------


Unfunded Pension Obligations

At December 31, 2002,  accumulated benefit obligations were in excess of pension
assets.  Pursuant to SFAS 87 "Employers' Accounting for Pensions", an additional
minimum   liability  would  normally  be  recorded  for  this  unfunded  pension
obligation. As allowed for under current accounting guidelines, this accrual can
be offset by a  corresponding  debit to an intangible  asset up to the amount of
accumulated  unrecognized prior service costs with the remaining amount recorded
as a direct charge to other comprehensive income.  However, as the pension plans
were merged into The KeySpan Retirement Plan, an additional minimum liability is
not determined based upon the subsidiary plan information, but rather based upon
the minimum liability associated with The KeySpan Retirement Plan. Therefore,  a
minimum liability is not recorded based upon the above plan information.









                                      F-19


<PAGE>

                               BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS

(6) Contractual Obligations and Contingencies (Continued)

Leases

Since  the  beginning  of  2002,  substantially  all  operating  leases  are the
obligation of KCS, a wholly owned subsidiary of KeySpan. The Company records, as
an inter-company expense, costs incurred for the use of leased equipment such as
buildings,  office equipment and vehicles.  These inter-company  expenses,  were
approximately  $5.2  million  in  2002  and  are  reflected  in  Operations  and
Maintenance  expense  in the  Statement  of  Operations.  Prior to 2002,  rental
expense was a direct  charge to the Company and was $7.4  million in 2001,  $2.3
million  for the period  November  8, 2000  through  December  31, 2000 and $8.7
million for the period January 1 through November 7, 2000.

In April 1999,  the Company  entered  into a 15 year  capital  lease for the LNG
facilities located in Salem and Lynn, Massachusetts.  A summary of property held
under capital leases as of December 31 is as follows:


------------------------------------------------------------------------------
In Thousands of Dollars                               2002               2001
------------------------------------------------------------------------------

LNG Facilities                                    $ 14,834           $ 14,834
Less: Accumulated Depreciation                       1,431                845
------------------------------------------------------------------------------
Total Capital Lease                               $ 13,403           $ 13,989
------------------------------------------------------------------------------



Under the terms of SFAS 71,  the timing of expense  recognition  on  capitalized
leases conforms with  regulatory  rate  treatment.  The Company has included the
rental payments on its capital leases in its cost of service for rate purposes.

The remaining  minimum rental  commitment for the capital leases at December 31,
2002 is  approximately  $1.6  million a year  through  2007,  and $10.3  million
thereafter.  Included in these future  obligations  are  interest and  executory
costs of approximately  $4.8 million.  As discussed above,  minimum rental lease
payments for operating leases are paid by KCS.

Fixed Charges Under Firm Contracts

     We have entered into various contracts for gas delivery, storage and supply
services.  The contracts have remaining  terms that cover from one to ten years.
Certain  of these  contracts  require  payment of annual  demand  charges in the
aggregate  amount of  approximately  $127.0  million.  We are  liable  for these
payments regardless of the level of service we require from third parties.  Such
charges  are  currently   recovered  from  utility  customers  through  the  gas
adjustment clause.






                                      F-20


                                BOSTON GAS COMPANY

                          NOTES TO FINANCIAL STATEMENTS


(6) Contractual Obligations and Contingencies (Continued)

Legal

From time to time we are subject to various legal proceedings arising out of the
ordinary course of our business.  We do not consider any of such  proceedings to
be material to our business or likely to result in a material  adverse effect on
our results of operations, financial condition and cash flows.


(7)   Fair Values of Financial Instruments

     The following methods and assumptions were used to estimate the fair values
     of financial instruments:

     Cash--The carrying amounts approximate fair value.

     Short-term  Debt--The  carrying  amounts of the Company's  short-term debt,
     including notes payable and gas inventory financing, approximate their fair
     value.

     Long-term  Debt--The  fair value of long-term  debt is  estimated  based on
     currently quoted market prices.

     Preferred  Stock--The  fair  value  of the  preferred  stock  is  based  on
     currently quoted market prices.

The carrying  amounts and estimated fair values of the Company's  long-term debt
and preferred stock at December 31, 2002 and 2001 are as follows:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
                                                            2002                              2001
-------------------------------------------------------------------------------------------------------------
In Thousands of Dollars                      Carrying Amount    Fair Value    Carrying Amount     Fair Value
-------------------------------------------------------------------------------------------------------------
<S>                                              <C>              <C>              <C>              <C>
Long-term debt                                  $ 223,403        $ 260,477        $ 223,989        $ 229,499
Preferred stock                                    13,840           14,067           15,289           15,209
-------------------------------------------------------------------------------------------------------------
                                                $ 237,243        $ 274,544        $ 239,278        $ 244,708
-------------------------------------------------------------------------------------------------------------
</TABLE>















                                      F-21


<PAGE>


                               BOSTON GAS COMPANY

                   NOTES TO FINANCIAL STATEMENTS--(Continued)



(8)        Related Party Transactions

On November 8, 2000,  KCS became an affiliate of the Company,  through KNE LLC's
merger with KeySpan.  KCS provides  financing to the Company for working capital
and gas  inventory  through a utility money pool. At December 31, 2002 and 2001,
we had  outstanding  borrowings of $67.2 million and $147.4  million for working
capital,   respectively,  and  $83.9  and  $85.4  million  for  fuel  inventory,
respectively.

KCS  also  provides  the  Company  with   services,   including   executive  and
administrative,  corporate affairs,  customer services,  environmental services,
financial  services  (including  accounting,  auditing,  risk  management,  tax,
treasury/finance),  human resources,  information  technology,  legal, materials
management and  purchasing,  and strategic  planning.  In 2002 and 2001, we were
charged $86.8 million and $37.3 million,  respectively,  for these services. The
increase  in  amounts  charged  by KCS is  primarily  due  to  the  labor  costs
associated with a large number of employees who were previously employees of the
Company, but are now employees of KCS.

KCS also  purchases  and/or  develops  and  implements  software  and  purchases
hardware  used  by the  Company.  The  amount  charged  to us by KCS  for  these
technology  assets  totaled  $18.0  and  $21.8  million  during  2002 and  2001,
respectively. These charges have been recorded as property assets on our Balance
Sheet.

In 2002 and  2001,  we were  charged  by KCS  $8.8  million  and  $7.3  million,
respectively,  for interest on working capital and gas inventory borrowings.  In
2000,  the  Company  expensed  $1.7  million for  interest on these  borrowings.
Interest  charged  is equal to actual  interest  incurred  by  KeySpan  to issue
commercial paper, plus a proportional share of the administrative costs incurred
in obtaining the funds to meet the combined short-term borrowing requirements of
the members of the Utility Pool Agreement.

As of December 31, 2002,  $650 million in advances were recorded on the books of
the Company  from  KeySpan  Corporation.  In 2002 and 2001,  we were  charged by
KeySpan  Corporation  $51.8 and $49.9  million for  interest  and debt  issuance
costs,  respectively.  In 2000,  we expensed  $5.5 million for interest and debt
issuance  costs on the  advance  outstanding  in 2000.  Interest  charges  equal
interest  incurred by KeySpan on debt  borrowings  issued by  KeySpan.  Issuance
expense is charged to the Company  from  KeySpan  equal to the  amortization  of
actual  issuance  costs  incurred  by  KeySpan on its debt  borrowings.  KeySpan
amortizes these costs over the life of the related KeySpan borrowings.














                                      F-22


<PAGE>



                               BOSTON GAS COMPANY

                   NOTES TO FINANCIAL STATEMENTS--(Continued)


(9)   Environmental Matters

The Company,  like many other companies in the natural gas industry, is party to
governmental  proceedings  requiring  investigation and possible  remediation of
former  manufactured  gas plant ("MGP")  operations,  including former operating
plants,  gas holder locations and satellite disposal sites. We may have or share
responsibility  under  applicable  environmental  laws for the remediation of 19
such sites.  A subsidiary of National  Grid USA  (formerly New England  Electric
System) has assumed responsibility for remediating 11 of these sites, subject to
a limited  contribution from the Company. In addition,  we are aware of 31 other
former MGP related  sites within our service  territory.  The National  Grid USA
subsidiary  has  provided  full  indemnification  to the Company with respect to
eight of the 31 sites.  At this time,  there is  substantial  uncertainty  as to
whether we have or share  responsibility  for  remediating  any of these  sites.
However,  no notice of responsibility has been issued to us for these sites from
any governmental environmental authority.

The Company has estimated its potential share of the costs of investigating  and
remediating the former MGP related sites and the non-MGP site in accordance with
SFAS No. 5,  "Accounting  for  Contingencies,"  and the  American  Institute  of
Certified  Public  Accountants   Statement  of  Position  96-1,   "Environmental
Remediation  Liabilities."  We estimate the  remaining  cost of its  MGP-related
environmental  cleanup  activities will be $28.9 million,  which amount has been
accrued  by us as a  reasonable  estimate  of  probable  cost for  known  sites.
However,  there can be no assurance that actual costs will not vary considerably
from these  estimates.  Factors  that may bear on actual  costs  differing  from
estimates include,  without limit, changes in regulatory  standards,  changes in
remediation  technologies  and practices and the type and extent of contaminants
discovered  at the sites.  Expenditures  incurred to date with  respect to these
MGP-related activities total $17.7 million.

By a rate order issued on May 25, 1990, the Department  approved the recovery of
all prudently incurred  environmental  response costs associated with former MGP
related sites over separate,  seven-year amortization periods,  without a return
on the  unamortized  balance.  The Company has recognized a regulatory  asset of
$36.9  million,   representing  the  expected  rate  recovery  of  environmental
remediation  costs. This amount is included in Deferred Charges and Other Assets
on the Balance Sheet.



















                                      F-23


<PAGE>


                               BOSTON GAS COMPANY

                   NOTES TO FINANCIAL STATEMENTS--(Continued)



(10)       Workforce Reduction Program

In November,  2000, as a result of the KeySpan  merger,  we recorded a liability
for $6.0 million for a severance  program  implemented  to reduce the workforce.
This  severance  program was to  continue  through  2002.  During the year ended
December  31,  2001,  we paid $1.3  million  for this  program  and  reduced our
liability  by $3.3  million  as a result  of lower  than  anticipated  costs per
employee and recorded a  corresponding  reduction  to  Goodwill.  The  remaining
liability at December 31, 2001 was $1.4  million.  In 2002,  approximately  $0.4
million was paid with the  remaining  liability  of  approximately  $0.2 million
reversed  and  recorded  to  earnings.   There  is  a  remaining   liability  of
approximately $0.8 million which is schedule to be paid out in 2003.

(11)       Derivatives

The utility  tariffs  associated  with our  operations  do not contain a weather
normalization  clause. As a result,  fluctuations from normal weather may have a
significant  positive  or  negative  effect on the  results  of  operations.  To
mitigate  the  effect of  fluctuations  from  normal  weather  on our  financial
position and cash flows,  we sold heating  degree-day call options and purchased
heating-degree day put options for the November 2002 - April 2003 winter season.
With respect to sold call options,  we are required to make a payment of $40,000
per heating degree day to our  counter-parties  when actual weather  experienced
during the November 2002 - April 2003 time frame is above 4,470  heating  degree
days, which equates to approximately 1% colder than normal weather. With respect
to  purchased  put  options,  we will  receive a $20,000 per heating  degree day
payment  from our  counter-parties  when actual  weather is below 4,150  heating
degree days, or is  approximately  7% warmer than normal.  Based on the terms of
such contracts,  we account for such instruments pursuant to the requirements of
EITF 99-2,  "Accounting for Weather Derivatives." In this regard, we account for
such  instruments  using  the  "intrinsic  value  method"  as set  forth in such
guidance.  During the fourth  quarter of 2002,  weather was  approximately  7.4%
colder than normal and we recorded a $3.3 million  reduction to revenues  with a
corresponding liability due to our counter-parties.

On April 1, 2002, we adopted  Implementation  Issue C16 of SFAS 133, "Accounting
for Derivative  Instruments  and Hedging  Activities" as amended and interpreted
incorporating SFAS 137 and 138 and certain  implementation  issues (collectively
"SFAS 133").  Issue C16 establishes new criteria that must be satisfied in order
for contracts that combine a forward contract and a purchased option contract to
be exempted as normal purchases and sales.

Based  upon a review  of its  physical  gas  purchase  commodity  contracts,  we
determined  that  certain  contracts  could no  longer  be  exempted  as  normal
purchases  from the  requirements  of SFAS 133. At December 31,  2002,  the fair
value of these contracts was a liability of $0.6 million.  Since these contracts
are for the  purchase  of  natural  gas sold to firm gas  sales  customers,  the
accounting for these contracts is subject to SFAS 71. Therefore,  changes in the
market value of these  contracts  are  recorded as a deferred  asset or deferred
liability on the Balance Sheet.





                                      F-24


<PAGE>



INDEPENDENT AUDITORS' REPORT

To the Shareholder and Board of Directors of Boston Gas Company:

We have  audited  the  accompanying  Balance  Sheet of Boston Gas  Company  (the
Company) (an indirectly  wholly-owned  subsidiary of KeySpan Corporation,) as of
December 31, 2002, and the related  Statements of Operations,  Retained Earnings
(Deficit),  Comprehensive Income (Loss), and Cash Flows for the year then ended.
Our audit also included the  financial  statement  schedule,  for the year ended
December 31, 2002,  listed in the Index to Financial  Statements  and Schedules.
These  financial  statements  and  the  financial  statement  schedule  are  the
responsibility of the Company's management.  Our responsibility is to express an
opinion on these  financial  statements and the financial  schedule based on our
audit.  The financial  statements of Boston Gas Company as of December 31, 2001,
and for the year then ended,  the period from November 8, 2000 through  December
31,  2000 and the period  from  January 1, 2000  through  November  7, 2000 were
audited by other  auditors  who have  ceased  operations.  Their  report,  dated
February 4, 2002, expressed an unqualified opinion on those statements.

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

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

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

As discussed above,  the financial  statements of the Company as of December 31,
2001,  and for the year then  ended,  the period from  November 8, 2000  through
December 31, 2000 and the period from  January 1, 2000 through  November 7, 2000
were  audited by other  auditors  who have  ceased  operations.  Note 1 to these
financial  statements has been revised to include the  transitional  disclosures
required by SFAS No. 142. Our audit  procedures  with respect to the disclosures
in Note 1 for the 2001 and 2000 periods  included  (i)  agreeing the  previously
reported net income (loss)  applicable for common stock to the previously issued
financial  statements and the  adjustments  to net income (loss)  applicable for
common stock  representing  amortization  expense  recognized  in those  periods
related  to  goodwill  to  the  Company's   underlying   records  obtained  from
management,  and (ii) testing the mathematical accuracy of the reconciliation of
adjusted net income  (loss) to reported net income  (loss)  available for common
stock.  In our opinion,  the disclosures in Note 1 are appropriate and have been
properly applied.  However,  we were not engaged to audit,  review, or apply any
procedures to the 2001 and 2000  financial  statements of the Company other than
with respect to such adjustments and, accordingly,  we do not express an opinion
or any other form of assurance on the 2001 and 2000 financial  statements  taken
as a whole.


DELOITTE & TOUCHE LLP

New York, New York
February 10, 2003


                                      F-25


<PAGE>


                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To Boston Gas Company:

We have  audited  the  accompanying  consolidated  balance  sheets of Boston Gas
Company (a Massachusetts  Corporation and an indirect wholly-owned subsidiary of
KeySpan  Corporation) and subsidiaries as of December 31, 2001 and 2000, and the
related consolidated  statements of earnings,  retained earnings,  comprehensive
income and cash flows for the year ended  December  31,  2001,  the period  from
November 8, 2000  through  December  31,  2000,  the period from January 1, 2000
through  November  7,  2000,  and  the  year  ended  December  31,  1999.  These
consolidated  financial  statements  are  the  responsibility  of the  Company's
management.  Our  responsibility is to express an opinion on these  consolidated
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  of Boston  Gas  Company  and
subsidiary as of December 31, 2001 and 2000 and the results of their  operations
and their cash flows for the year  ended  December  31,  2001,  the period  from
November 8, 2000  through  December  31,  2000,  the period from January 1, 2000
through  November 7, 2000,  and the year ended  December 31, 1999, in conformity
with accounting principles generally accepted in the United States.

Our  audits  were  made for the  purpose  of  forming  an  opinion  on the basic
financial  statements  taken as a whole.  The  schedule  listed  in the index to
consolidated  financial  statements is presented for purposes of complying  with
the  Securities and Exchange  Commission's  rules and is not a 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

New York, New York
February 4, 2002

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




                                      F-26



<PAGE>

<TABLE>
<CAPTION>
                                                                   BOSTON GAS COMPANY
                                                             INTERIM FINANCIAL INFORMATION
                                             For the two years ended December 31, 2002 and 2001 (Unaudited)


                                                                                    Quarters Ended 2002
-------------------------------------------------------------------------------------------------------------------------------
(In Thousands)                                                      March 31       June 30         Sept. 30          Dec. 31
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>            <C>               <C>             <C>
Operating revenues                                                  $ 244,291      $ 101,771         $  64,424       $ 228,625
Operating margin                                                    $ 110,804      $  54,886         $  40,592       $  87,006
Operating earnings (loss) including income taxes                    $  41,539      $   3,683         $  (6,153)      $  23,211
Net earnings (loss) applicable to common stock                      $  25,262      $ (11,814)        $ (23,692)      $   6,795
-------------------------------------------------------------------------------------------------------------------------------


                                                                                    Quarters Ended 2001
-------------------------------------------------------------------------------------------------------------------------------
(In Thousands)                                                      March 31       June 30         Sept. 30          Dec. 31
-------------------------------------------------------------------------------------------------------------------------------
Operating revenues                                                  $ 401,020      $ 148,042         $  84,462        $195,414
Operating margin                                                    $ 109,273      $  49,897         $  36,626        $ 74,459
Operating earnings (loss) including income taxes                    $  32,652      $  (4,555)        $ (11,193)       $ 10,181
Net earnings (loss) applicable to common stock                      $  19,626      $ (20,446)        $ (26,949)       $ (3,482)
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>


In  the  opinion  of  management,   the  annual   financial  data  includes  all
adjustments,  unless otherwise noted in the accompanying  footnotes,  consisting
only of normal  recurring  accruals,  necessary for a fair  presentation of such
information.
































                                      F-27


<PAGE>




<TABLE>
<CAPTION>
                                                                                                                SCHEDULE II
                                                                        BOSTON GAS COMPANY
                                                                VALUATION AND QUALIFYING ACCOUNTS

                                              ----------------------------------------------------------------------------------
                                                                                        Charged        Net
                                                     Balance at      Charged          (Credited)to   Deductions
                                                     Beginning of   (Credited)           other         from           Balance at
(In Thousands)                                          Period       to Income          Accounts     Reserves       End of Period
For the Year Ended December 31, 2002
<S>                                                   <C>             <C>                <C>           <C>             <C>
Reserves for doubtful accounts                       $ 14,730        $ 15,503          $      -       $ 15,567        $ 14,666
                                                     ========        ========          ========       ========        ========
Reserve for self-insurance                           $    843        $  1,250          $      -       $  1,425        $    668
                                                     ========        ========          ========       ========        ========
Reserve for environmental expenses                   $ 31,878        $      -          $  3,047       $      -        $ 28,831
                                                     ========        ========          ========       ========        ========


For the Year Ended December 31, 2001
Reserves for doubtful accounts                       $ 13,681        $ 11,192          $      -       $ 10,143        $ 14,730
                                                     ========        ========          ========       ========        ========
Reserve for self-insurance                           $  2,891        $    675          $      -       $  2,723        $    843
                                                     ========        ========          ========       ========        ========
Reserve for environmental expenses                   $ 18,000        $      -          $ 13,878       $      -        $ 31,878
                                                     ========        ========          ========       ========        ========


For the Period From November 8, 2000
Through December 31, 2000
Reserves for doubtful accounts                       $ 12,329        $  2,687          $      -       $  1,335        $ 13,681
                                                     ========        ========          ========       ========        ========
Reserve for self-insurance                           $ 2,901         $    250          $      -       $    260        $  2,891
                                                     ========        ========          ========       ========        ========
Reserve for environmental expenses                   $ 18,000        $      -          $      -       $      -        $ 18,000
                                                     ========        ========          ========       ========        ========

For the Period From January 1, 2000
Through November 7, 2000(Predecessor)
Reserves for doubtful accounts                       $ 14,816        $  7,761          $      -       $ 10,248        $ 12,329
                                                     ========        ========          ========       ========        ========
Reserve for self-insurance                           $  3,913        $  1,616          $      -       $  2,628        $  2,901
                                                     ========        ========          ========       ========        ========
Reserve for environmental expenses                   $ 18,000        $      -          $      -       $      -        $ 18,000
                                                     ========        ========          ========       ========        ========



</TABLE>











                                      F-28