<PAGE>


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

                                    FORM 10-K

      (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, 2001

                                       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)

            One Beacon Street                            (617) 742-8400
       Boston, Massachusetts 02108              (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 Eastern Enterprises.

      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.

<PAGE>


                               BOSTON GAS COMPANY

                                    FORM 10-K

                       Fiscal Year Ended December 31, 2001

                                TABLE OF CONTENTS

  Item
  ----
   No                                 Topic                                 Page
   --                                 -----                                 ----

                                     PART I

 1.  Business
     General..............................................................     1
     Markets and Competition..............................................     1
     Gas Throughput.......................................................     2
     Gas Supply...........................................................     2
     Regulation...........................................................     3
     Seasonality and Working Capital......................................     4
     Environmental Matters................................................     5
     Employees............................................................     5
 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...........     9
 8.  Financial Statements and Supplementary Data..........................    10
 9.  Changes in and Disagreements with Accountants on Accounting and
     Financial Disclosure.................................................    10

                                 PART III

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

                                  PART IV

14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K......    12

<PAGE>

                                     PART I

Item 1. Business.

General

      Boston Gas Company D/B/A KeySpan Energy Delivery New England (the
"Company"), is engaged in the transportation and sale of natural gas to
approximately 555,000 residential, commercial and industrial customers in
Boston, Massachusetts and 73 other communities in eastern and central
Massachusetts. The Company is the largest natural gas distribution company in
New England and has been in business for 179 years.

      The Company is a wholly-owned subsidiary of Eastern Enterprises
("Eastern"). On November 8, 2000, KeySpan Corporation ("KeySpan") acquired all
of the common stock of Eastern. The transaction was accounted for as a purchase,
with KeySpan being the acquiring company. Prior to this transaction, Eastern had
owned Boston Gas Company since 1929. KeySpan is a registered holding company
under the Public Utility Holding Company Act ("PUCHA") 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
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. The Company's 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 the Company 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 the Company separately from the
purchase of gas supply, which the customer may buy from third-party suppliers.
The Company views these third-party suppliers as partners in marketing gas and
increasing throughput and expects to work closely with them to facilitate the
unbundling process and ensure a smooth transition, especially in the tracking
and processing of transactions. The Company has also implemented programs to
educate customers about the opportunity to purchase gas from third-party
suppliers, while still relying on the utility for delivery. As of December 31,
2001, the Company had approximately 4,500 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 the Company's revenues, it has no impact
on its operating earnings. The Company earns all of its margins on the local
distribution of gas and none on the resale of the commodity itself.

Markets and Competition

      The Company competes with other fuel distributors, primarily oil dealers,
throughout its service territory. Over the last nine years, the Company has
increased its share in the total stationary energy market from 31% to 38%. This
market share compares to the national level of approximately 44%, and represents
a growth opportunity for the Company. However, future market share 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.


                                        1

<PAGE>


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
1999-2001.

                                                    Years Ended December 31,
                                                    ------------------------
                                                2001         2000         1999
                                               ------       ------       ------
Residential .............................        41.9         43.2         39.3
Commercial and industrial ...............        21.9         25.4         27.3
Off-system sales ........................         0.2          2.6          5.6
                                               ------       ------       ------
      Total sales .......................        64.0         71.2         72.2
Transportation of customer-owned gas ....        61.9         55.8         56.4
Less: Off-system sales ..................        (0.2)        (2.6)        (5.6)
                                               ------       ------       ------
      Total throughput ..................       125.7        124.4        123.0
                                               ======       ======       ======
      Total firm throughput .............       124.9        122.4        109.1
                                               ======       ======       ======

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

      In 2001, residential customers comprised 91% of the Company's customer
base, while commercial and industrial establishments accounted for the remaining
9%. Volumetrically, residential customers accounted for 34% of total firm
throughput, while commercial and industrial customers accounted for 66% of total
firm throughput. Approximately 69% of commercial and industrial customers' total
throughput was transportation-only service. Sithe Energy, an independent power
generator on the Company's system, was responsible for approximately 28% of this
transportation throughput under a contract which was renewed through February,
2003.

      No customer, or group of customers under common control, accounted for 2%
or more of total firm revenues in 2001.

Gas Supply

      The following table in BCF provides information with respect to the
Company's sources of supply during the three years 1999-2001.

                                                     Years Ended December 31,
                                                     ------------------------
                                                 2001        2000         1999
                                                ------      ------       ------
Natural gas purchases ....................        52.3        59.6         65.9
Underground storage withdrawal ...........         6.0        12.5          9.9
Liquefied natural gas ("LNG") purchases ..         1.9         5.3          1.9
                                                ------      ------       ------
      Total source of supply .............        60.2        77.4         77.7
Company use, unbilled and other ..........         3.8        (6.2)        (5.5)
                                                ------      ------       ------
      Total sales ........................        64.0        71.2         72.2
                                                ======      ======       ======

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


                                       2

<PAGE>

      The vast majority of the Company's gas supplies are transported on
interstate pipeline systems to the Company's 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 the Company's service territory, the peak daily and
annual capacity and the contract expiration dates are as follows:

<TABLE>
<CAPTION>
                                                                                        Capacity in             Expiration
                                                                                           BCF                    Dates
                                                                                           ---                    -----
                                                                                   Daily          Annual
                                                                                   -----          ------
                      Pipeline
            ------------------------------
<S>                                                                                  <C>            <C>        <C>
Algonquin Gas Transmission Company ("Algonquin").............................        0.29           86.0       2005-2012
Tennessee Gas Pipeline Company ("Tennessee").................................        0.21           77.1       2003-2012
                                                                                     ----          -----
                                                                                     0.50          163.1
                                                                                     ====          =====
</TABLE>

      In 1999, the Company restructured its long-term capacity contracts with
Tennessee Gas Pipeline. The majority of these Tennessee contracts are up for
renewal in 2003. Less than 1% of the Company's capacity on Algonquin expired in
2002. In addition, the Company has firm capacity contracts on interstate
pipelines upstream of the Algonquin and Tennessee pipelines to transport natural
gas purchased by the Company from various areas of gas production.

      The Company has 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. The Company utilizes its
existing transportation contracts to transport gas from the storage fields to
its service territory. Supplemental supplies of LNG and propane are produced by
and purchased from foreign and domestic sources.

      The Company and its Massachusetts affiliates, Colonial Gas Company and
Essex Gas Company, continue to operate under the portfolio management contract
with El Paso Merchant Energy - Gas, L.P. This arrangement has a three-year
primary term that commenced on November 1, 1999. El Paso is responsible for
providing the majority of the city gate supply requirements to the three
companies and managing certain of the companies' upstream capacity, underground
storage and term supply contracts. The Department approved the contract in
October 1999.

      Peak day firm throughput in BCF was 0.63 in 2001, 0.80 in 2000, and 0.64
in 1999. The Company provides 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 at points on the Company's
distribution system. The Company owns propane air facilities and an LNG facility
in Dorchester, Massachusetts. The Company also leases two LNG facilities sited
on land owned by the Company in Salem and Lynn, Massachusetts and leases space
in facilities located in Providence, Rhode Island and Everett, Massachusetts.
The Company considers its peak day sendout capacity, based on its total supply
resources, to be adequate to meet the requirements of its firm customers.

Regulation

      The Company's 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. The Company's cost
of gas adjustment clause, billed to firm sales customers, allows for the
semiannually, and based on certain criteria, 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, the Company
collects 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.

                                        3

<PAGE>

      The Company's rates for local transportation service are governed by the
five-year performance-based rate plan approved by the Department's 1996 order in
D.P.U. 96-50. Under the plan, the Company's local transportation rates are
recalculated annually to reflect inflation for the previous 12 months and
reduced by a productivity factor. The plan also provides for penalties if the
Company fails to meet specified service quality measures, with a maximum
potential exposure of $1 million. There is a margin sharing mechanism whereby
25% of earnings in excess of a 15% return on year-ending equity are to be passed
back to ratepayers. Similarly, ratepayers absorb 25% of any shortfall below a 7%
return on year-ending equity. Because rates under the Plan expire on October 31,
2002, Boston Gas has represented to the DTE that by April, 2002 it will address
what rate plan it will propose to succeed the Plan.

      In the Department's Order of D.P.U. 96-50, it set the productivity factor
at 1.50% and expanded the service quality penalty beyond the $1 million proposed
by the Company. The Company appealed the Department's order in D.P.U. 96-50 and
the Supreme Judicial Court issued an order vacating: 1) the "accumulated
inefficiencies" component of the productivity factor, thereby reducing the
productivity factor from 1.5% to 0.5%; and 2) the expansion of the service
quality penalty beyond $1 million, and remanded these matters to the Department
for further proceedings. On January 16, 2001, the Department issued its order in
the remand proceeding. The order limited the maximum service quality adjustment
to $1 million but imposed a 0.5 percent accumulated inefficiencies component to
the productivity factor to be implemented retroactively as of November 1, 1999
thereby increasing the productivity factor from 0.5% to 1.0%. On January 30,
2001, the Company appealed the imposition of the 0.5% accumulated inefficiencies
adjustment to the Supreme Judicial Court and was granted a stay of the
Department's order pending a final decision by the Court on the merits of the
appeal. On March 7, 2002, the Supreme Judicial Court ruled in favor of Boston
Gas Company and eliminated the accumulated inefficiencies factor of 0.5%. During
the first quarter of 2002,the Company will reverse a previously recorded loss
provision of approximately $4.0 million because of this favorable ruling.

      On November 1, 2001, the DTE issued an order requiring all Massachusetts
electric and gas utilities to develop service quality plans effective January 1,
2002 and providing potential penalties up to two percent of distribution service
revenues. These plans, and their potential penalties, will differ from the
service quality plan and potential penalties incorporated in the Company's
current Plan.

      All of the Company's 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
the Company's tariffs for all its residential customers 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 marketers, 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.

Seasonality and Working Capital

      The Company's revenues, earnings and cash flow are highly seasonal because
most of its transportation services and sales are directly related to
temperature conditions. Since the majority of its 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, the Company bills its customers over the heating season for the majority
of the pipeline demand charges paid by the Company over the entire year. This
difference, along with other costs of gas distributed but unbilled, is reflected
as deferred gas costs 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.

                                        4

<PAGE>

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 Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.

Employees

      As of December 31, 2001, the Company had approximately 1,300 employees,
73% of whom are organized in local unions with which the Company has collective
bargaining agreements. In March 2002, the Company entered into a new four-year
collective bargaining agreement with the largest bargaining units representing
union employees; these agreements expire in 2006.

Item 2. Properties.

      The Company operates three LNG facilities in Dorchester, Salem, and Lynn,
Massachusetts. These facilities provide the Company with local storage of gas,
because the stored LNG can be vaporized into the Company's distribution system
to supplement pipeline gas in periods of high demand. The Company owns the
Dorchester facility. The Company owns the real property at the Salem and Lynn
facilities and rents the storage facilities under a long-term lease arrangement.

      The Company owns propane-air facilities at various locations throughout
its service territory.

      On December 31, 2001, the Company's distribution system included
approximately 6,100 miles of gas mains, 440,000 services and 561,000 active
customer meters. A majority of the gas mains consist of cast iron and bare
steel, which require ongoing maintenance and replacement.

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

      In 2001, the Company's capital expenditures were approximately $112
million. Capital expenditures were principally made for improvements to the
distribution system, for system expansion to meet customer growth and for
productivity improvements. The Company plans to spend approximately $94 million
for similar purposes in 2002.

Item 3. Legal Proceedings.

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

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

      No matter was submitted to a vote of Security Holders in the fourth
quarter of 2001.


                                       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,
typically a price cap plan, 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 have the opportunity to
select only the services they desire.


                                       6

<PAGE>

                                     PART II

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

      Eastern Enterprises, 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

As discussed under Note 1 of Notes to Consolidated Financial Statements, the
Company became an indirect wholly-owned subsidiary of KeySpan Corporation when
its parent company, Eastern Enterprises, merged with KeySpan on November 8,
2000.

Year ended December 31, 2001

Net loss applicable to common stock for 2001 was $ 31.3 million. Weather for
this period was 4.5% warmer than normal. As a result of the merger, this period
included a full year of amortization of goodwill of $19.4 million and interest
and debt issuance costs of $49.8 million related to the $650 million advance
from KeySpan.

Period from November 8, 2000 through December 31, 2000

      Weather for this period was 11% colder than normal. As a result of the
merger, this period includes amortization of goodwill of $3.2 million and
interest and debt issuance costs of $5.5 million related to the $600 million
advance from KeySpan Corporation.

Period from January 1, 2000 through November 7, 2000

      Weather for the period was normal. This period includes merger-related
expenses of approximately $23.3 million consisting primarily of separation
payments to officers, payment of vested stock options and other compensation
related matters associated with the KeySpan merger.

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 Disclosures About Market
Risk" relating to our future outlook, anticipated capital expenditures, future
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding, are forward-looking statements. Such forward-looking
statements reflect numerous assumptions and involve a number of risks and
uncertainties and actual results may differ materially from those discussed in
such statements. Among the factors that could cause actual results to differ
materially are: general economic conditions, especially in Massachusetts;
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


                                       7

<PAGE>

structure; inflationary trends and interests rates; and other risks detailed
from time to time in other reports and other documents filed by the Company with
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" and " Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" contained herein.

LIQUIDITY AND CAPITAL RESOURCES

      On November 8, 2000, KeySpan Corporate Services, a KeySpan subsidiary,
became an affiliate of the Company, through the Company's transaction with
KeySpan. KeySpan Corporate Services 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 Corporate Services 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 merger, the Company recorded in November 2000, a $600
million advance payable to KeySpan. During 2001, 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 actual
issuance costs incurred by KeySpan on its debt borrowings. These costs are
amortized over the life of the borrowings.

      The Company expects capital expenditures for 2002 to be approximately $94
million. 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, is sufficient to meet 2002
capital expenditures, working capital requirements, preferred dividend payments
and normal debt repayments.

OTHER MATTERS

Regulation

      The Company's 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. The Company's cost
of gas adjustment clause, billed to firm sales customers, allows for the
semiannually, and based on certain criteria, 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, the Company
collects 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 are governed by the
five-year performance-based rate plan approved by the Department's 1996 order in
D.P.U. 96-50. Under the plan, the Company's local transportation rates are
recalculated annually to reflect inflation for the previous 12 months and
reduced by a productivity factor. The plan also provides for penalties if the
Company fails to meet specified service quality measures, with a maximum
potential exposure of $1 million. There is a margin sharing mechanism whereby
25% of earnings in excess of a 15% return on year-ending equity are to be passed
back to ratepayers. Similarly, ratepayers absorb 25% of any shortfall below a 7%
return on year-ending equity. Because rates under the Plan expire on October 31,
2002, Boston Gas has represented to the DTE that by April, 2002 it will address
what rate plan it will propose to succeed the Plan.

                                       8

<PAGE>

      In the Department's Order of D.P.U. 96-50, it set the productivity factor
at 1.50% and expanded the service quality penalty beyond the $1 million proposed
by the Company. The Company appealed the Department's order in D.P.U. 96-50 and
the Supreme Judicial Court issued an order vacating: 1) the "accumulated
inefficiencies" component of the productivity factor, thereby reducing the
productivity factor from 1.5% to 0.5%; and 2) the expansion of the service
quality penalty beyond $1 million, and remanded these matters to the Department
for further proceedings. On January 16, 2001, the Department issued its order in
the remand proceeding. The order limited the maximum service quality adjustment
to $1 million but imposed a 0.5 percent accumulated inefficiencies component to
the productivity factor to be implemented retroactively as of November 1, 1999
thereby increasing the productivity factor from 0.5% to 1.0%. On January 30,
2001, the Company appealed the imposition of the 0.5% accumulated inefficiencies
adjustment to the Supreme Judicial Court and was granted a stay of the
Department's order pending a final decision by the Court on the merits of the
appeal. On March 7, 2002, the Supreme Judicial Court ruled in favor of Boston
Gas Company and eliminated the accumulated inefficiencies factor of 0.5%. During
the first quarter of 2002, the Company will reverse a previously recorded loss
provision of approximately $4.0 million because of this favorable ruling.

      On November 1, 2001, the DTE issued an order requiring all Massachusetts
electric and gas utilities to develop service quality plans effective January 1,
2002 and providing potential penalties up to two percent of distribution service
revenues. These plans, and their potential penalties, will differ from the
service quality plan and potential penalties incorporated in the Company's
current plan.

      All of the Company's 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
the Company's tariffs for all its residential customers 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 marketers, 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.

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 Notes to Consolidated 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 more competitive and deregulated environments.
In addition, we are exposed to commodity price risk and interest 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 DTE directed Massachusetts gas distribution companies to
undertake a collaborative process with other stakeholders to develop common
principles under which comprehensive gas service unbundling might proceed. A
settlement agreement by the Local Distribution Company's ("LDC's") and the


                                       9

<PAGE>

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

      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.

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.

      None.


                                       10

<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.


                                       11

<PAGE>

                                     PART IV

Item 14. 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).*


                                       12

<PAGE>

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
            Herewith).

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).

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 Registrant's Annual Report 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).*

10.9        --Amendment to Exhibit 10.9, 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).*

10.10       --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).*

10.11       --Gas 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).*

10.12       --Amendments to Exhibit 10.12, Gas Sales Agreement between the
            Company and Alberta Northeast Gas, Ltd., dated as of October 1,
            1992; May 5, 1993; November 27, 1995; March 14, 1996; and November
            27, 1995. (Filed as Exhibit 10.12.1 to the Annual Report of the
            Company on Form 10-K For the year ended December 31, 1998).*

10.13       --Firm 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).*

10.13.1     --Agreement between the Company and Iroquois Gas Transmission System
            L.P. amending Exhibit 10.13 as of November 3, 1998. (Filed as
            Exhibit 10.13.1 to the Annual Report of the Company on Form 10-K for
            the year ended December 31, 1999).*

10.14       --Firm 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).*

10.15       --Gas 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).*


                                       13

<PAGE>

10.16       --Gas 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).*

10.17       --Gas 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).*

10.18       --Gas 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).*

10.19       --Gas 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).*

10.20       --Gas 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).*

10.21       --Gas 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).*

10.22       --Gas 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).*

10.23       --Gas 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).*

10.24       --Gas 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).*

10.25       --Gas 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).*

10.26       --Gas 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).*


                                       14

<PAGE>

10.27       --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 10.33 to the Annual Report of the Company on Form 10-K for
            the year ended December 31, 1997).*

10.27.1     --Agreement between the Company and Texas Eastern Transmission
            amending Exhibits 10.27, 10.15, 10.16, 10.17, 10.29, and 10.30 dated
            as of October 29, 1998. (Filed as Exhibit 10.27.1 to the Annual
            Report of the Company on Form 10-K for the year ended December 31,
            1999).*

10.28       --Gas 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).*

10.29       --Gas 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. (Filed as
            Exhibit 10.35 to the Annual Report of the Company on Form 10-K for
            the year ended December 31, 1997).*

10.30       --Gas 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).*

10.31       --Gas Transportation Contract between the Company and Texas Eastern
            Transmission dated October 29, 1999 providing for transportation of
            approximately 3,000 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, 1999).*

10.32       --Gas 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). *

10.33       --Gas 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).*

10.34       --Agreement between the Company and Tennessee Gas Pipeline dated as
            of September 1, 1993 providing for transportation of approximately
            10,500 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, 1999).*

10.35       --Agreement 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).*

10.36       --Agreement 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).*


                                       15

<PAGE>

10.37       --Contract Restructuring Agreement between the Company and Tennessee
            Gas Pipeline dated as of August 2, 1999 amending Exhibits 10.1,
            10.31 and 10.32. (Filed as Exhibit 10.37 to the Annual Report of the
            Company on Form 10-K for the year ended December 31, 1999).*

10.38       --Redacted 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. (Filed as Exhibit 10.1 to the Form 10-K of Eastern
            Enterprises for the year ended December 31, 1999.).*

10.39       --Amended 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).*

10.40       --Precedent 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 Herewith).

10.41       --Agreement between the Company and Maritimes Northeast Gas Pipeline
            Limited Partnership dated June 18, 1999 providing for transportation
            of approximately 43,200 Dekatherms of natural gas per day. (Filed
            Herewith).

99.1        A Letter by the Company to the Securities and Exchange Commission
            regarding representations from Arthur Andersen LLP. (Filed herewith)

      There were no reports on Form 8-K filed in the Fourth Quarter of 2001.

*     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.


                                       16

<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


                                             /s/  JOSEPH F. BODANZA

                               By: _____________________________________________
                                                 Joseph F. Bodanza
                                               Senior Vice President
                                    Finance, Accounting and Regulatory Affairs
                                   (Principal Financial and Accounting Officer)

Dated: March 29, 2002

      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 29th day of March, 2002.

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

 /s/  CHESTER R. MESSER
                                                 Director and President
___________________________
     Chester R. Messer


                                       17

<PAGE>


                               BOSTON GAS COMPANY

            INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
            (Information required by Items 8 and 14 (a) of Form 10-K)

<TABLE>
<S>                                                                                                  <C>
Report of Independent Public Accountants ......................................................         F-21
Consolidated Statements of Earnings 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 ....................................          F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000 ..................................      F-3 and F-4
Consolidated Statements of Retained Earnings and Consolidated Statements of Comprehensive
      Income 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 .................................................................          F-5
Consolidated Statements of 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 ....................................          F-6
Notes to Consolidated Financial Statements ....................................................      F-7 to F-20
Interim Financial Information for the Two Years Ended December 31, 2001 (Unaudited) ...........         F-22
Schedule 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:
          Schedule II--Valuation and Qualifying Accounts ......................................         F-23
</TABLE>

      Schedules other than that listed above have been omitted as the
information has been included in the consolidated financial statements and
related notes or is not applicable nor required.


                                       F-1

<PAGE>

                               BOSTON GAS COMPANY

                       CONSOLIDATED STATEMENTS OF EARNINGS

<TABLE>
<CAPTION>
                                                                             Period from         Period from
                                                              Year        November 8, 2000    January 1, 2000         Year
                                                              Ended            through             through            Ended
                                                          December 31,      December 31,         November 7,       December 31,
                                                          ------------      ------------         -----------       ------------
                                                              2001              2000                2000               1999
                                                              ----              ----                ----               ----
                                                                             (In Thousands)
                                                                                               (Predecessor)     (Predecessor)
<S>                                                        <C>               <C>                 <C>               <C>
Operating revenues ................................        $ 828,938         $ 202,842           $ 453,783         $ 592,719
Cost of gas sold ..................................          558,683           131,516             247,548           306,500
                                                           ---------         ---------           ---------         ---------
Operating margin ..................................          270,255            71,326             206,235           286,219
                                                           ---------         ---------           ---------         ---------
Operating expenses:
      Operations ..................................          127,988            20,098              99,363           117,790
      Maintenance .................................           28,968             5,161              24,304            23,037
      Depreciation and amortization ...............           52,261            10,745              39,515            45,779
      Amortization of goodwill ....................           19,439             3,226                  --                --
      Income taxes ................................           (9,056)            9,718              (3,468)           24,093
      Taxes, other than income ....................           23,570             4,557              18,918            22,042
      Merger related expenses .....................               --               101              23,347                --
                                                           ---------         ---------           ---------         ---------
            Total operating expenses ..............          243,170            53,606             201,979           232,741
                                                           ---------         ---------           ---------         ---------
Operating earnings ................................           27,085            17,720               4,256            53,478
Other earnings, net ...............................            2,775               451                 719             1,979
                                                           ---------         ---------           ---------         ---------
Earnings before interest expense ..................           29,860            18,171               4,975            55,457
                                                           ---------         ---------           ---------         ---------
Interest expense:
      Long-term debt ..............................           16,835             2,806              13,984            16,775
      Other, including amortization of debt expense           43,867             3,501              (4,017)             (240)
      Less--Interest during construction ..........             (686)             (202)               (704)             (852)
                                                           ---------         ---------           ---------         ---------
            Total interest expense ................           60,016             6,105               9,263            15,683
                                                           ---------         ---------           ---------         ---------
Net (loss) earnings ...............................          (30,155)           12,066              (4,288)           39,774
Preferred stock dividends .........................            1,096               183               1,174             1,862
                                                           ---------         ---------           ---------         ---------
(Loss) earnings applicable to common stock ........        $ (31,251)        $  11,883           $  (5,462)        $  37,912
                                                           =========         =========           =========         =========
</TABLE>

        The accompanying notes are an integral part of these consolidated
                             financial statements.


                                      F-2

<PAGE>

                               BOSTON GAS COMPANY

                           CONSOLIDATED BALANCE SHEETS

                                     ASSETS

<TABLE>
<CAPTION>
                                                                                             December 31,
                                                                                    -------------------------------
                                                                                       2001                 2000
                                                                                    -----------         -----------
                                                                                            (In Thousands)
<S>                                                                                 <C>                 <C>
Gas plant, at cost .........................................................        $ 1,070,610         $   969,429
Construction work-in-progress ..............................................             27,875              26,688
      Less-Accumulated depreciation ........................................           (425,163)           (388,668)
                                                                                    -----------         -----------
            Net plant ......................................................            673,322             607,449
                                                                                    -----------         -----------
Current assets:
      Cash .................................................................              3,104               3,916
      Accounts receivable, less reserves of $14,730 at December 31, 2001 and
         $13,681 at December 31, 2000 ......................................             80,663             100,326
      Accounts receivable - affiliates .....................................              8,851                  --
      Accrued utility revenue ..............................................             50,693              71,823
      Deferred gas costs ...................................................             15,670              77,665
      Natural gas and other inventories, at average cost ...................             79,544              57,082
      Materials and supplies, at average cost ..............................              3,996               4,062
      Prepaid expenses .....................................................                377               1,112
                                                                                    -----------         -----------
            Total current assets ...........................................            242,898             315,986
                                                                                    -----------         -----------
Other assets:
      Goodwill .............................................................            790,285             771,089
      Deferred postretirement benefits cost ................................             42,585              44,085
      Deferred charges and other assets ....................................             56,261              37,089
                                                                                    -----------         -----------
            Total other assets .............................................            889,131             852,263
                                                                                    -----------         -----------
            Total assets ...................................................        $ 1,805,351         $ 1,775,698
                                                                                    ===========         ===========
</TABLE>

        The accompanying notes are an integral part of these consolidated
                              financial statements.


                                      F-3

<PAGE>

                               BOSTON GAS COMPANY

                           CONSOLIDATED BALANCE SHEETS

                         CAPITALIZATION AND LIABILITIES

<TABLE>
<CAPTION>
                                                                                              December 31,
                                                                                     ------------------------------
                                                                                        2001                2000
                                                                                     -----------         ----------
                                                                                             (In Thousands)
<S>                                                                                  <C>                 <C>
Capitalization:
   Common stockholder's investment--
      Common stock, $100 par value--
         Authorized and outstanding--514,184 shares .........................        $    51,418         $   51,418
         Amounts in excess of par value .....................................            360,575            374,377
         Retained earnings ..................................................            (19,368)            11,883
         Accumulated other comprehensive income .............................               (692)                --
                                                                                     -----------         ----------
            Total common stockholder's investment ...........................            391,933            437,678
   Cumulative preferred stock, $1 par value,
      (liquidation preference, $25 per share)--
      Authorized 1,200,000 shares; outstanding 622,700 shares at December 31,
         2001 and 682,700 at December 31, 2000 ..............................             15,289             16,742
   Long-term obligations, less current portion ..............................            223,403            224,017
                                                                                     -----------         ----------
            Total capitalization ............................................            630,625            678,437
   Advance from KeySpan .....................................................            650,000            600,000
                                                                                     -----------         ----------
            Total capitalization and advance from KeySpan ...................          1,280,625          1,278,437
                                                                                     -----------         ----------
Current liabilities:
      Current portion of long-term obligations ..............................                586                385
      Note payable utility pool .............................................            147,350            114,843
      Note payable utility pool-gas inventory financing .....................             85,401             82,307
      Accounts payable ......................................................             99,608            104,657
      Accounts payable - affiliates .........................................                 --                686
      Accrued taxes .........................................................              5,740              1,728
      Accrued income taxes ..................................................             (2,432)            10,758
      Accrued interest ......................................................             11,377              4,411
      Customer deposits .....................................................              1,884              2,013
      Other current liabilities .............................................                157              2,015
                                                                                     -----------         ----------
            Total current liabilities .......................................            349,671            323,803
                                                                                     -----------         ----------
Reserves and deferred credits:
      Deferred income taxes .................................................             73,609             80,136
      Unamortized investment tax credits ....................................              2,556              3,398
      Postretirement benefits obligation ....................................             50,901             50,393
      Environmental liability ...............................................             31,878             18,000
      Other .................................................................             16,111             21,531
                                                                                     -----------         ----------
            Total reserves and deferred credits .............................            175,055            173,458
                                                                                     -----------         ----------
            Total capitalization and liabilities ............................        $ 1,805,351         $1,775,698
                                                                                     ===========         ==========
</TABLE>

        The accompanying notes are an integral part of these consolidated
                              financial statements.


                                      F-4

<PAGE>

                               BOSTON GAS COMPANY

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

<TABLE>
<CAPTION>
                                                          Period From        Period From
                                                          November 8,        January 1,
                                           Year Ended     2000 through      2000 through       Year Ended
                                          December 31,    December 31,       November 7,      December 31,
                                              2001            2000              2000              1999
                                              ----            ----              ----              ----
                                                                  (In Thousands)
                                                                           (Predecessor)     (Predecessor)
<S>                                        <C>              <C>              <C>               <C>
Balance at beginning of period ....        $ 11,883         $     --         $ 189,517         $ 178,857
      Net (loss) earnings .........         (30,155)          12,066            (4,288)           39,774
      Preferred Stock dividend ....          (1,096)            (183)           (1,174)           (1,862)
      Common Stock dividend .......              --               --           (22,496)          (27,252)
                                           --------         --------         ---------         ---------
Balance at end of period ..........        $(19,368)        $ 11,883         $ 161,559         $ 189,517
                                           ========         ========         =========         =========
</TABLE>

                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
                                                          Period From       Period From
                                                          November 8,       January 1,
                                          Year Ended      2000 through     2000 through      Year Ended
                                         December 31,     December 31,      November 7,     December 31,
                                             2001             2000             2000             1999
                                             ----             ----             ----             ----
                                                                  (In Thousands)
                                                                           (Predecessor)     (Predecessor)
<S>                                        <C>              <C>              <C>               <C>
Net (loss) earnings ....................   $(30,155)        $ 12,066         $  (4,288)        $  39,774
Accrued unfunded pension obligation ....     (1,065)              --                --                --
Income tax effect ......................        373               --                --                --
                                           --------         --------         ---------         ---------
Comprehensive (loss) income.............   $(30,847)        $ 12,066         $  (4,288)        $  39,774
                                           ========         ========         =========         =========
</TABLE>

        The accompanying notes are an integral part of these consolidated
                              financial statements.


                                      F-5

<PAGE>

                               BOSTON GAS COMPANY

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                                Period From     Period From
                                                                             November 8, 2000   January 1,
                                                               Year Ended         through       2000 through      Year Ended
                                                              December 31,     December 31,     November 7,      December 31,
                                                                  2001             2000             2000             1999
                                                               ---------         --------         --------         --------
                                                                                      (In Thousands)
Cash flows from operating activities:                                                           (Predecessor)    (Predecessor)
<S>                                                            <C>               <C>              <C>              <C>
   Net (loss) earnings ................................        $ (30,155)        $ 12,066         $ (4,288)        $ 39,774
   Adjustments to reconcile net (loss) earnings to cash
      provided by operating activities:
      Depreciation and amortization ...................           71,700           13,971           39,515           45,779
      Deferred taxes ..................................          (35,895)           7,011           17,718            1,536
      Other changes in assets and liabilities:
         Accounts receivable ..........................           10,812          (61,736)          46,483          (20,815)
         Accrued utility margin .......................           21,130          (16,287)          14,029           (5,920)
         Inventory ....................................          (22,396)          18,987          (31,560)          (4,344)
         Deferred gas costs ...........................           61,995          (51,225)         (28,066)           6,420
         Accounts payable .............................           (5,735)          25,060           32,314           (1,017)
         Accrued income taxes .........................           16,178            5,249          (20,495)          (3,335)
         Other ........................................           (2,929)           3,237            4,056            6,850
                                                               ---------         --------         --------         --------
Cash provided by (used in)operating activities ........           84,705          (43,667)          69,706           64,928
                                                               ---------         --------         --------         --------
Cash flows from investing activities:
   Capital expenditures ...............................         (111,735)         (21,802)         (52,958)         (57,256)
   Net cost of removal ................................           (6,834)          (1,272)          (4,628)          (4,379)
                                                               ---------         --------         --------         --------
Cash used for investing activities ....................         (118,569)         (23,074)         (57,586)         (61,635)
                                                               ---------         --------         --------         --------
Cash flows from financing activities:
   Changes in advance from KeySpan ....................           50,000               --               --               --
   Changes in notes payable, net ......................           32,507           54,843            8,800           22,300
   Changes in inventory financing .....................            3,094           13,719           14,568            5,721
   Dividends paid on common and preferred stock .......          (51,096)            (183)         (23,670)         (29,114)
   Purchase of preferred treasury stock ...............           (1,500)              --           (9,933)          (3,000)
   Amortization of preferred stock issuance costs .....               47                4              217               94
                                                               ---------         --------         --------         --------
Cash provided by (used in) financing activities .......           33,052           68,383          (10,018)          (3,999)
                                                               ---------         --------         --------         --------
Increase (decrease) in cash ...........................             (812)           1,642            2,102             (706)
Cash at beginning of period ...........................            3,916            2,274              172              878
                                                               ---------         --------         --------         --------
Cash at end of period .................................        $   3,104         $  3,916         $  2,274         $    172
                                                               =========         ========         ========         ========
Supplemental disclosure of cash flow information:
   Cash paid during the year for:
         Interest, net of amounts capitalized .........        $  75,438         $ 18,255         $     --         $ 18,462
                                                               =========         ========         ========         ========
         Income taxes .................................        $   2,489         $ (1,718)        $    115         $ 26,486
                                                               =========         ========         ========         ========
</TABLE>

        The accompanying notes are an integral part of these consolidated
                             financial statements.


                                      F-6

<PAGE>

                               BOSTON GAS COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Accounting Policies

General

      Boston Gas Company (the "Company") 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 Eastern Enterprises ("Eastern") and an indirect
wholly-owned subsidiary of KeySpan Corporation ("KeySpan"), a registered holding
company under the Public Utility Holding Company Act of 1935, as amended.

Basis of Presentation

      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 No. 71 ("SFAS 71"),
"Accounting for the Effects of Certain Types of Regulation."

      The Consolidated 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.

Merger and Goodwill

      On November 8, 2000, KeySpan acquired all of the common stock of Eastern
for $64.56 per share in cash. The transaction has been accounted for using the
purchase method of accounting for business combinations. The purchase price was
allocated to the net assets acquired of Eastern 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 is 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.

      As prescribed by SFAS 121 "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of", the carrying value of
goodwill is reviewed if the facts and circumstances, such as significant
declines in sales, earnings or cash flows, or material adverse changes in the
business climate suggest it might be impaired. If this review indicates that
goodwill is not recoverable, as determined based upon the estimated undiscounted
cash flows of the equity acquired, impairment would be measured by comparing the
carrying value of the investment in such entity to its fair value. Fair value
would be determined based on quoted market values, appraisals, or discounted
cash flows. For the year ended December 31, 2001, no write-down of goodwill was
determined to be necessary.


                                      F-7

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(1) Accounting Policies (Continued)

      On January 1, 2002, the Company 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. The annual impairment test is to be performed
within six months of adopting SFAS 142 with any resulting impairment reflected
as either a change in accounting principle, or a charge to operations in the
financial statements. The result of this analysis is not complete at this time,
and the Company is unable to determine the impact this analysis may have on its
results of operations or financial condition. However, a change in the
measurement of the realization of goodwill could result in a significant change
in its carrying value.

Regulation

      The Company is regulated as to rates, accounting and other matters by the
Massachusetts Department of Telecommunications and Energy ("the Department").
Therefore, the Company accounts for the economic effects of regulation in
accordance with the provisions of SFAS 71. In the event the Company determines
that it 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
$79 million as of December 31, 2001. Criteria that give rise to the
discontinuance of SFAS 71 include (1) increasing competition that restricts the
Company's ability to establish prices to recover specific costs or (2) a
significant change in the manner in which rates are set by regulators from
cost-based regulation to another form of regulation. The Company has reviewed
these criteria and believes that the continuing 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 the amounts that are to
be credited to customers through the rate-making process.

      The following regulatory assets were reflected in the consolidated balance
sheets as of December 31:

                                                        2001               2000
                                                      -------            -------
                                                           (In Thousands)

Post-retirement benefit costs ............            $42,585            $44,085
Environmental costs ......................             35,917             18,060
                                                      -------            -------
                                                      $78,502            $62,145
                                                      =======            =======

      Regulatory liabilities total approximately $6,801,000 and $7,694,000 at
December 31, 2001 and 2000 respectively, and relate to income taxes.

      As of December 31, 2001, all of the Company's regulatory assets and
liabilities are reflected in rates charged or credited to customers over periods
ranging from 1 to 20 years. For additional information regarding deferred income
taxes, post-retirement benefit costs and environmental costs, see Notes 2, 5 and
9, respectively.


                                      F-8

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(1) Accounting Policies (Continued)

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.

Cost of Gas Adjustment Clause and Deferred Gas Costs

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

Depreciation

      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 5.0% for all periods presented. Amortization
is provided on intangible assets, principally software, over the estimated
useful life of the asset.

      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.

Recent Accounting Pronouncements

      In June of 2001, the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations". The Standard requires entities to record the fair value
of a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity will capitalize a
cost increasing the carrying amount of the related long-lived asset. Over time,
the liability is accreted to its then present value, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The standard is effective for fiscal
years beginning after June 15, 2002, with earlier application encouraged. The
Company is currently evaluating the impact, if any, that the Statement may have
on its results of operations and financial condition.


                                      F-9

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(1) Accounting Policies (Continued)

      SFAS 144, " Accounting for the Impairment of Disposal of Long-Lived
Assets," is effective January 1, 2002, and addresses accounting and reporting
for the impairment of 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.
We currently do not anticipate that implementation of this Statement will have a
significant effect on our results of operations and financial condition.

Reclassifications

      Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.

(2) Income Taxes

      For 2001, the Company will file a consolidated income tax return with
KeySpan Corporation. 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 1999, the
period January 1 through November 7, 2000, and the period form November 8
through December 31, 2000, the Company filed a consolidated federal income tax
return with Eastern Enterprises. For these periods the Company followed the
policy, established for the group, of providing for income taxes payable on a
separate company basis. The Company's effective income tax rate was (23.1)% in
2001, 44.6% for the period from November 8 through December 31, 2000, (44.7)%
for the period from January 1 through November 7, 2000, and 38.2% in 1999. State
income taxes and the nondeductibility of goodwill amortization represent the
majority of the difference between the effective rate and the federal income tax
rate of 35% for 2001 and for the period from November 8 through December 31,
2000 and state income taxes represent the majority of the difference for the
period from January 1 through November 7, 2000 and 1999.


                                      F-10

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(2) Income Taxes (Continued)

      A summary of the provision for income taxes is as follows:

<TABLE>
<CAPTION>
                                                              Period from        Period from
                                            Year Ended     November 8 through  January 1 through     Year Ended
                                           December 31,       December 31,        November 7,       December 31,
                                           ------------       ------------        -----------       ------------
                                                2001              2000               2000               1999
                                              --------           ------            --------           --------
                                                                (In Thousands)
                                                                                 (Predecessor)     (Predecessor)
<S>                                           <C>                <C>               <C>                <C>
Current--
      Federal ......................          $ 22,378           $2,258            $(17,695)          $ 17,756
      State ........................             4,461              449              (3,491)             4,801
                                              --------           ------            --------           --------
            Total current provision             26,839            2,707             (21,186)            22,557
Deferred--
      Federal ......................           (30,198)           5,835              14,713              2,244
      State ........................            (5,697)           1,176               3,005               (708)
                                              --------           ------            --------           --------
            Total deferred provision           (35,895)           7,011              17,718              1,536
                                              --------           ------            --------           --------
Provision for income taxes .........          $ (9,056)          $9,718            $ (3,468)          $ 24,093
                                              ========           ======            ========           ========
</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, 2001 the Company had a regulatory liability of $1,336,000
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. The Company also has a regulatory liability for excess
deferred taxes being returned to customers over a 30-year period pursuant to a
1988 rate order with a balance to be refunded to customers of $5,466,000 as of
December 31, 2001.

      For income tax purposes, the Company uses 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, 2001 and 2000 are
as follows:

<TABLE>
<CAPTION>
                                                                               2001              2000
                                                                            ---------         ---------
                                                                                   (In Thousands)
<S>                                                                         <C>               <C>
Assets:
      Regulatory liabilities .......................................        $   2,718         $   3,133
      Other ........................................................           31,784            21,621
                                                                            ---------         ---------
         Total deferred tax assets .................................           34,502            24,754
                                                                            ---------         ---------
Liabilities:
      Accelerated depreciation .....................................          (85,333)          (84,533)
      Deferred gas costs ...........................................            2,604           (39,303)
      Other ........................................................          (19,752)          (12,080)
                                                                            ---------         ---------
         Total deferred tax liabilities ............................         (102,481)         (135,916)
                                                                            ---------         ---------
         Total net deferred taxes ..................................        $ (67,979)        $(111,162)
                                                                            =========         =========

Deferred income taxes are reflected in the balance sheet as follows:
   Accrued income taxes (current deferred) .........................        $   5,630         $ (31,026)
   Deferred income taxes (long-term) ...............................        $ (73,609)        $ (80,136)
                                                                            ---------         ---------
                                                                            $ (67,979)        $(111,162)
                                                                            =========         =========
</TABLE>


                                      F-11

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(2) Income Taxes (Continued)

      Investment tax credits are deferred and credited to income over the lives
of the property giving rise to such credits. The credit to income for 2001 was
$842,000, $140,000 for the period from November 8 through December 31, 2000,
$702,000 for the period from January 1 through November 7, 2000, and $842,000 in
1999.

(3) Debt

Long-term Obligations

      The following table provides information on long-term obligations as of
December 31:

<TABLE>
<CAPTION>
                                                                   2001              2000
                                                                 ---------         ---------
                                                                        (In Thousands)
<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) ...........................      13,989            14,402
Less current portion .........................................        (586)             (385)
                                                                 ---------         ---------
                                                                 $ 223,403         $ 224,017
                                                                 =========         =========
</TABLE>

      There are no sinking fund requirements for the next three years related to
the $210,000,000 of Medium-Term Notes outstanding at December 31, 2001 and none
are callable prior to maturity. In 2005, $15,000,000 of 8.875% Medium-Term Notes
Series A, mature. In 2006, $12,000,000 of 8.09% Medium-Term Notes Series B,
mature.

      Annual maturities of capital lease obligations for 2002 through 2006 are
$586,000, $840,000, $891,000, $945,000 and $ 1,003,000, respectively.

Utility Money Pool Borrowings

      KeySpan Corporate Services provides financing to the Company for working
capital and gas inventory through the Company's participation in a Utility Money
Pool. At December 31, 2001, the Company had outstanding borrowings of $
147,350,000 and $ 85,401,000 for working capital and gas inventory,
respectively. Interest charged equals interest incurred by KeySpan Corporate
Services to borrow funds to meet the needs of the Company, plus a proportional
share of the administrative costs incurred in obtaining the required funds. All
costs related to the gas inventory borrowings are recoverable from customers
through the CGAC. The average yearly rate on these borrowings was 4.16 %.

Advance from KeySpan Corporation

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


                                      F-12

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(4) Preferred Stock

      The Company has outstanding 622,700 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
not callable prior to 2003. On September 3, 2001, the Company redeemed 60,000
shares, or 5% at $25 per share. On September 1, 2000, the Company redeemed
120,000 shares, or 10% of the outstanding shares, at $25 per share. In addition
to the 120,000 shares redeemed in 2000, the Company purchased 277,300 shares on
the open market which were subsequently retired.

(5) Retiree Benefits

      The Company provides retirement benefits for substantially all of its
employees. These plans include pensions, health and life insurance benefits.

      Pension benefits for salaried plans are based on salary and years of
service, while union retirement and welfare plans are based on negotiated
benefits and years of service. Employees hired before 1993 who are participants
in the pension plans become eligible for post-retirement health care benefits if
they reach retirement age while working for the Company. The funding of
retirement and employee 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").


                                      F-13

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(5) Retiree Benefits (Continued)

      The net cost for these plans and agreements charged to expense was as
follows:

Pensions

<TABLE>
<CAPTION>
                                                                              Period from         Period from
                                                                               November 8           January 1
                                                          Year Ended            through              through          Year Ended
                                                          December 31,        December 31,          November 7,       December 31,
                                                              2001                2000                 2000               1999
                                                            --------             -------             --------           --------
                                                                                        (In Thousands)
                                                                                                  (Predecessor)       (Predecessor)
<S>                                                         <C>                  <C>                 <C>                <C>
Service cost ...................................            $  2,964             $   410             $  2,272           $  2,819
Interest cost on projected benefit obligation ..              10,690               1,835                8,170              8,988
Expected return on plan assets .................             (12,701)             (2,176)             (10,698)           (12,127)
Amortization of prior service cost .............                  --                  --                1,090              1,173
Amortization of transitional obligation ........                  --                  --                  186                217
Recognized actuarial (gain)/loss ...............                  60                  --                 (821)              (760)
Settlement and curtailment gain ................                  --                  --                   --             (1,216)
                                                            --------             -------             --------           --------
Total net pension cost .........................            $  1,013             $    69             $    199           $   (906)
                                                            ========             =======             ========           ========
</TABLE>

Health Care

<TABLE>
<CAPTION>
                                                                              Period from         Period from
                                                                               November 8           January 1
                                                          Year Ended            through              through          Year Ended
                                                          December 31,        December 31,          November 7,       December 31,
                                                              2001                2000                 2000               1999
                                                            --------             -------             --------           --------
                                                                                      (In Thousands)
                                                                                                   (Predecessor)      (Predecessor)
<S>                                                         <C>                  <C>                 <C>                <C>
Service cost ...................................            $  1,358             $   131             $    624           $    757
Interest cost on accumulated benefits obligation               6,687               1,110                4,736              5,458
Expected return on plan assets .................              (2,349)               (405)              (1,787)            (2,066)
Amortization of prior service cost .............                  --                  --                 (882)            (1,124)
Recognized actuarial (gain)/loss ...............                 636                  --                 (726)              (900)
Regulatory deferral ............................                  --                 486                4,646              5,808
                                                            --------             -------             --------           --------
Total net retiree health care cost .............            $  6,332             $ 1,322             $  6,611           $  7,933
                                                            ========             =======             ========           ========
</TABLE>

The previous tables do not reflect retirement pension enhancements of $2,066,000
for 1999.


                                      F-14

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(5) Retiree Benefits (Continued)

      The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of Company plans and amounts recorded
in the Company's balance sheet as of December 31, 2001, December 31, 2000, and
November 7, 2000, using actuarial measurement dates of December 31, 2001,
December 31, 2000, and November 7, 2000, respectively:

<TABLE>
<CAPTION>
                                                                       Period from          Period from
                                                                        November 8           January 1
                                                 Year Ended              through              through
                                                 December 31,          December 31,          November 7,
                                                     2001                  2000                 2000
                                                  ---------             ---------             ---------
                                                                      (In Thousands)
                                                                                            (Predecessor)
Pensions
--------
<S>                                               <C>                   <C>                   <C>
Change in benefit obligation
Balance at beginning of period .......            $ 157,285             $ 146,703             $ 131,873
Service cost .........................                2,964                   410                 2,272
Interest cost ........................               10,690                 1,835                 8,170
Plan merger ..........................                   --                    --                 6,283
Amendment ............................                4,419                    --                    --
Benefits paid ........................               (8,403)               (1,191)               (6,700)
Actuarial loss (gain).................               (4,002)                9,528                 4,805
                                                  ---------             ---------             ---------
Balance at end of period .............            $ 162,953             $ 157,285             $ 146,703
                                                  =========             =========             =========
Change in plan assets
Fair value, beginning of period ......            $ 153,328             $ 153,934             $ 154,143
Plan merger ..........................                   --                    --                 5,707
Actual return on plan assets .........               (8,968)                  585                   784
Employer contributions ...............               19,000                    --                    --
Benefits paid ........................               (8,403)               (1,191)               (6,700)
Adjustment ...........................               (4,717)                   --                    --
                                                  ---------             ---------             ---------
Fair value at end of period ..........            $ 150,240             $ 153,328             $ 153,934
                                                  =========             =========             =========
Reconciliation of funded status
Funded status ........................            $ (12,713)            $  (3,957)            $   7,231
Unrecognized actuarial loss (gain) ...                   --                11,118                (5,800)
Unrecognized transition obligation ...               33,085                    --                    --
Unrecognized prior service ...........                4,419                    --                    --
                                                  ---------             ---------             ---------
Net amount recognized for period .....            $  24,791             $   7,161             $   1,431
                                                  =========             =========             =========
Amounts recognized in balance sheet
Prepaid benefit cost .................            $  21,678             $   7,161             $   1,431
Accrued benefit liability ............               (1,998)                   --                    --
Intangible assets ....................                4,419                    --                    --
Accumulated other comprehensive income                  692                    --                    --
                                                  ---------             ---------             ---------
Net amount ...........................            $  24,791             $   7,161             $   1,431
                                                  =========             =========             =========
</TABLE>


                                      F-15

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(5) Retiree Benefits (Continued)

      The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of Company plans and amounts recorded
in the Company's balance sheet as of December 31, 2001, December 31, 2000 and
November 7, 2000, using actuarial measurement dates of December 31, 2001,
December 31, 2000, and November 7, 2000, respectively:

<TABLE>
<CAPTION>
                                                                   Period from          Period from
                                                                    November 8           January 1
                                              Year Ended             through              through
                                              December 31,         December 31,          November 7,
                                                  2001                 2000                 2000
                                               ---------             --------             --------
                                                                  (In Thousands)
                                                                                        (Predecessor)
<S>                                            <C>                   <C>                  <C>
Health Care
-----------

Change in benefit obligation
Balance at beginning of period .........       $  87,440             $ 78,452             $ 78,223
Service cost ...........................           1,358                  131                  623
Interest cost ..........................           6,686                1,110                4,736
Plan participant contribution ..........              21                   --                   --
Benefits paid ..........................          (6,488)                (467)              (5,135)
Actuarial loss .........................          11,860                8,214                    5
                                               ---------             --------             --------
Balance at end of period ...............       $ 100,877             $ 87,440             $ 78,452
                                               =========             ========             ========
Change in plan assets
Fair value, beginning of period ........       $  27,432             $ 28,600             $ 25,220
Actual return on plan assets ...........             783               (1,168)               3,380
Employer contributions .................           5,947                  467                5,135
Benefits paid ..........................          (6,488)                (467)              (5,135)
Plan participant contribution ..........              21                   --                   --
                                               ---------             --------             --------
Fair value at end of period ............       $  27,695             $ 27,432             $ 28,600
                                               =========             ========             ========
Reconciliation of funded status
Funded status ..........................       $ (73,182)            $(60,008)            $(49,852)
Unrecognized actuarial loss (gain)......          22,577                9,788              (23,100)
                                               ---------             --------             --------
Net amount recognized for period .......       $ (50,605)            $(50,220)            $(72.952)
                                               =========             ========             ========
Amounts recognized in balance sheet
Accrued benefit liability ..............       $ (50,605)            $(50,220)            $(72,952)
                                               =========             ========             ========
</TABLE>

      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. Plan assets are
invested in debt and equity marketable securities.


                                      F-16

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(5) Retiree Benefits (Continued)

      Following are the weighted-average assumptions used in developing the
projected benefit obligation:

<TABLE>
<CAPTION>
                                                           Period from      Period from
                                                            November 8       January 1
                                            Year Ended       through          through         Year Ended
                                           December 31,    December 31,     November 7,       December 31,
                                               2001            2000             2000              1999
                                           ------------    ------------     -----------       ------------
                                                                           (Predecessor)      (Predecessor)
<S>                                         <C>                 <C>              <C>            <C>
Discount rate............................      7.0%             7.0%             7.5%              7.5%
Return on plan assets....................      8.5%             8.5%             8.5%              8.5%
Increase in future compensation..........      4.0%             5.0%             5.0%           4.0 - 4.5%
Health care inflation trend..............   5.0 - 10.0%         8.0%             8.0%           8.0 - 10.0%
</TABLE>

      The health care inflation rate for 2002 is assumed to be 10%. 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 2001 would have the following effects:

<TABLE>
<CAPTION>
                                                              One-                One-
                                                           Percentage-         Percentage-
                                                         Point Increase      Point Decrease
                                                         --------------      --------------
                                                                   (In Thousands)
<S>                                                         <C>                <C>
Service cost and interest cost components.............      $   586            $   (535)
Post-retirement benefit obligation....................      $ 6,468            $ (6,035)
</TABLE>

Unfunded Pension Obligations

At December 31, 2001, accumulated benefit obligations were in excess of pension
assets. Pursuant to FAS 87 "Employers' Accounting for Pensions", the Company was
required to record an additional $5.1 million minimum liability for this
unfunded pension obligation. As allowed for under current accounting guidelines,
this accrual can be offset by a corresponding debit to a long-term asset up to
the amount of accumulated unrecognized prior service costs. Any remaining amount
is to be recorded as a direct charge to equity. Therefore, at year-end, the
Company recorded a $4.4 million debit in Deferred Charges Other and a $0.7
million debit in Accumulated Other Comprehensive Income. In December 2002, we
will re-measure the accumulated benefit obligations and pension assets, and
adjust the accrual and deferrals as appropriate.

(6) Leases

      The Company leases certain facilities and equipment under long-term leases
which expire on various dates through the year 2016. Total rentals charged to
income under all lease agreements were $7,425,000 in 2001, $2,247,000 for the
period November 8 through December 31, 2000, $8,685,000 for the period January 1
through November 7, 2000, and $9,846,000 in 1999. The Company has capitalized
leases for two LNG facilities. A summary of property held under capital leases
as of December 31 is as follows:

<TABLE>
<CAPTION>
                                                      2001                 2000
                                                    -------              -------
                                                           (In Thousands)
<S>                                                 <C>                  <C>
LNG Facilities ...............................      $14,834              $14,834
Buildings ....................................           --                6,000
                                                    -------              -------
                                                    $14,834              $20,834
Less--Accumulated depreciation ...............          845                6,432
                                                    -------              -------
Total Capital Leases .........................      $13,989              $14,402
                                                    =======              =======
</TABLE>


                                      F-17

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(6) Leases (Continued)

      In April 1999, the Company entered into a 15 year lease agreement for the
LNG facilities located in Salem and Lynn, Massachusetts. The facilities had
previously been leased by the Company's subsidiary, Mass LNG, which became
inactive in 1999.

      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 financing leases in its cost of service for
rate purposes.

      The Company also has various operating lease agreements for office
facilities and other equipment. The remaining minimum rental commitment for
these and all other noncancellable leases, including the financing leases, at
December 31, 2001 is as follows:

<TABLE>
<CAPTION>
                                                                              Capital           Operating
Year                                                                           Leases            Leases
----                                                                           ------            ------
                                                                                   (In Thousands)
<S>                                                                           <C>                <C>
2002.....................................................................     $  1,378           $ 6,394
2003.....................................................................        1,584             5,535
2004.....................................................................        1,584             4,554
2005.....................................................................        1,584             3,600
2006.....................................................................        1,584             2,844
Later Years..............................................................       11,880            31,718
                                                                              --------           -------
Total minimum lease payments.............................................     $ 19,594           $54,645
                                                                                                 =======
Less--Amount representing interest and executory costs...................       (5,605)
                                                                              --------
Present value of minimum lease payments on capital leases................     $ 13,989
                                                                              ========
</TABLE>

(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, 2001 and 2000 are as follows:

<TABLE>
<CAPTION>
                                                         2001                                 2000
                                             ---------------------------             ------------------------
                                             Carrying                                Carrying
                                              Amount          Fair Value              Amount        Fair Value
                                             --------         ----------             --------       ---------
                                                                        (In Thousands)
<S>                                          <C>               <C>                   <C>             <C>
Long-term debt.........................      $223,989          $229,499              $224,402        $229,138
Preferred stock........................      $ 15,289          $ 15,209              $ 16,742        $ 13,203
</TABLE>


                                      F-18

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(8) Related Party Transactions

      In 2001, the Company was charged $37,333,000 by KeySpan Corporate Services
for services, which included costs associated with: 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.

      KeySpan Corporate Services also purchases and/or develops and implements
software and purchases hardware which are or will be used by the Company.
Capital costs charged to the Company for these technology assets totaled
$21,762,000 during 2001.

      The Company paid Eastern $833,000 for the period November 8 through
December 31, 2000, $4,167,000 for the period January 1 through November 7, 2000,
and $4,500,000 in 1999 for legal, tax and corporate services rendered.

      The Company paid $775,000 in 2001, $129,000 for the period November 8
through December 31, 2000, $646,000 for the period January 1 through November 7,
2000, and $775,000 annually in 1999 to lease an operations center from an
affiliated company.

      On November 8, 2000, KeySpan Corporate Services became an affiliate of the
Company, through Eastern's merger with KeySpan. KeySpan Corporate Services
provides financing to the Company for working capital and gas inventory through
the Company's participation in a Utility Money Pool. At December 31, 2001, the
Company had outstanding borrowings of $147,350,000 and $85,401,000 for working
capital and fuel inventory, respectively. In 2001, the Company was charged by
KeySpan Corporate Services $4,830,000 and $2,466,000 for interest on working
capital and fuel inventory borrowings, respectively. At December 31, 2000, the
Company had outstanding borrowings of $114,843,000 and $82,307,000 for working
capital and fuel inventory, respectively. In 2000, the Company expensed $868,000
and $811,000 for interest on these working capital and gas inventory borrowings,
respectively. Interest charged is equal to actual interest incurred by KeySpan
Corporate Services to borrow funds to meet the needs of the Company, 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, 2001, $650 million in advances were recorded on the
books of the Company from KeySpan Corporation. During 2001, an additional $50
million had been advanced from KeySpan. A $50 million dividend was than paid to
KeySpan and charged against "Amounts in excess of par value." In 2001, the
Company was charged by KeySpan Corporation $48,609,000 and $1,225,000 for
interest and debt issuance costs, respectively. In 2000, the Company expensed
$5,504,000 for interest and debt issuance costs on this advance. Interest
charged is equal to actual interest incurred by KeySpan Corporation on such
advances by KeySpan Corporation. Issuance expense is charged to the Company from
KeySpan Corporation equal to the actual issuance costs incurred by KeySpan
Corporation on such advances. These costs are amortized over the life of the
borrowings.

(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. The
Company may have or


                                      F-19

<PAGE>

                               BOSTON GAS COMPANY

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(9) Environmental Matters (Continued)

share responsibility under applicable environmental laws for the remediation of
19 such sites. A subsidiary of New England Electric System ("NEES") has assumed
responsibility for remediating 11 of these sites, subject to a limited
contribution from the Company. The Company also may have or share responsibility
for the remediation of one non-MGP site. 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." The Company
estimates the remaining cost of its MGP-related environmental cleanup activities
will be $31.9 million, which amount has been accrued by the Company 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.

      The Company is aware of 31 other former MGP related sites within its
service territory. The NEES 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 the Company has or shares responsibility
for remediating any of these sites. No notice of responsibility has been issued
to the Company for these sites from any governmental environmental authority.

      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 an insurance
receivable of $3.0 million, reflecting a negotiated settlement with an insurance
carrier for MGP-related environmental expense indemnity, and a regulatory asset
of $28.9 million, representing the expected rate recovery of environmental
remediation costs, net of the insurance settlement. In light of the indemnity
agreement with the NEES subsidiary, the Department rate order on MGP-related
cost recovery, and the expected cost of remediating the non-MGP site, the
Company believes that it is not probable that actual costs will materially
affect its financial condition or results of operations.

(10) Workforce Reduction Program

      As a result of the KeySpan merger, the Company implemented a severance
program in an effort to reduce the workforce. In 2000, The Company recorded a
liability of $6 million associated with this severance program. During the year
ended December 31, 2001, the Company reduced this liability by $3.3 million as a
result of lower than anticipated costs per employee and recorded a corresponding
reduction to Goodwill. This severance program is targeted to reduce the
workforce by 80 employees and will continue through 2002. At December 31, 2001,
the Company paid $1.3 million for these programs and had a remaining liability
of $1.4 million.


                                      F-20

<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 subsidiary 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


                                      F-21

<PAGE>

                               BOSTON GAS COMPANY

                          INTERIM FINANCIAL INFORMATION
              For the Two Years Ended December 31, 2001 (Unaudited)

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

<CAPTION>
                                                                                      Period from     Period from
                                                Three Months Ended                     October 1       November 8
                                   ----------------------------------------------       through          through
                                      March 31        June 30         Sept. 30         November 7        Dec. 31
                                   (Predecessor)   (Predecessor)    (Predecessor)    (Predecessor)     -----------
                                   -------------   -------------    -------------    -------------
                                                                    (In Thousands)
<S>                                   <C>             <C>              <C>              <C>              <C>
2000
Operating revenues ...........        $248,598        $ 93,459         $ 71,399         $ 40,327         $202,842
Operating margin .............        $103,457        $ 48,752         $ 36,450         $ 17,576         $ 71,326
Operating earnings (loss) ....        $ 28,177        $   (904)        $ (8,007)        $(15,010)        $ 17,720
Net earnings (loss) applicable
 to common stock .............        $ 25,030        $ (3,900)        $(10,790)        $(15,802)        $ 11,883
</TABLE>

      In the opinion of management, the quarterly 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-22

<PAGE>

                                                                     SCHEDULE II

                               BOSTON GAS COMPANY

                        VALUATION AND QUALIFYING ACCOUNTS

                                 (In Thousands)

<TABLE>
<CAPTION>
                                                                                         Additions
                                                                                         ---------
                                                                                                                Net
                                                                      Balance at    Charged      Charged     Deductions   Balance at
                                                                       Beginning   (Credited)    to Other       from          End
                         Description                                   Of Period   to Income     Accounts     Reserves     Of Period
          ------------------------------------------                   ---------   ---------     --------     --------     ---------

<S>                                                                   <C>          <C>           <C>          <C>           <C>
                                For the Year Ended December 31, 2001

Reserves for doubtful accounts .....................................    $13,681    $  11,192     $      --    $  10,143     $14,730
                                                                        =======    =========     =========    =========     =======
Reserve 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 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 self-insurance .............................................    $ 3,913    $   1,616     $      --    $   2,628     $ 2,901
                                                                        =======    =========     =========    =========     =======
Reserve for environmental expenses .................................    $18,000    $      --     $      --    $      --     $18,000
                                                                        =======    =========     =========    =========     =======

                   For the Year Ended December 31, 1999
                               (Predecessor)

Reserves for doubtful accounts .....................................    $15,651    $  10,975     $      --    $  11,810     $14,816
                                                                        =======    =========     =========    =========     =======
Reserve self-insurance .............................................    $ 2,964    $   2,829     $      --    $   1,880     $ 3,913
                                                                        =======    =========     =========    =========     =======
Reserve for environmental expenses .................................    $18,750    $      --     $      --    $     750     $18,000
                                                                        =======    =========     =========    =========     =======
</TABLE>

                                      F-23