<PAGE>

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                                 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, 2000

                                      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 0-10007

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

            Massachusetts                           04-3480443
   (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:

<TABLE>
<CAPTION>
             Title of Each Class               Exchange
             -------------------               --------
<S>                                            <C>
                    None                         None
</TABLE>

          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.

   Indicate the number of shares outstanding of the registrant's class of
common stock as of March 1, 2001.

        All common stock, 100 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.

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<PAGE>

                              COLONIAL GAS COMPANY

                                   FORM 10-K

                      Fiscal Year Ended December 31, 2000

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
 Item No.                              Topic                               Page
 --------                              -----                               ----

                                     PART I

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

                                    PART II

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

                                    PART III

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

                                    PART IV

          Exhibits, Financial Statement Schedules and Reports on Form 8-
   14.     K............................................................    11
</TABLE>
<PAGE>

                                    PART I

Item 1. Business.

 General

   Colonial Gas Company D/B/A KeySpan Energy Delivery New England (the
"Company"), a Massachusetts corporation formed in 1849, is engaged in the
transportation and sale of natural gas to approximately 163,000 residential,
commercial and industrial customers in 24 municipalities located northwest of
Boston ("Merrimack Valley" area) and on Cape Cod.

   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. Previous to this
transaction, Eastern had owned the Company since August 31, 1999.

   On August 31, 1999, the Company completed a merger with Eastern in a
transaction with an enterprise value of approximately $474 million. In
effecting the transaction, Eastern paid $150 million in cash, net of cash
acquired and including transaction costs, issued approximately 4.2 million
shares of common stock valued at $186 million and assumed $138 million of
debt.

   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,
2000, the Company had approximately 240 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
and electricity suppliers, throughout its service territory. Over the last
three years, the Company has increased its market share in the total
stationary energy market from 42% to 45%. This market share compares to the
national level of approximately 42% 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 1998-2000.

<TABLE>
<CAPTION>
                                                                   Years Ended
                                                                   December 31,
                                                                  --------------
                                                                  2000 1999 1998
                                                                  ---- ---- ----
   <S>                                                            <C>  <C>  <C>
   Residential................................................... 13.0 12.0 11.4
   Commercial and industrial.....................................  7.4  6.8  6.2
                                                                  ---- ---- ----
     Total sales................................................. 20.4 18.8 17.6
   Transportation of customer-owned gas..........................  3.8  6.4  7.4
                                                                  ---- ---- ----
     Total throughput............................................ 24.2 25.2 25.0
                                                                  ==== ==== ====
     Total firm throughput....................................... 22.4 22.1 22.4
                                                                  ==== ==== ====
</TABLE>

   In 2000, residential customers comprised 90% of the Company's customer
base, while commercial and industrial establishments accounted for the
remaining 10%. Volumetrically, residential customers accounted for 58% of
total firm throughput, while commercial and industrial customers accounted for
42% of total firm throughput. Approximately 34% of commercial and industrial
customers' total throughput was transportation-only service.

   No customer, or group of customers under common control, accounted for 2%
or more of total firm revenues in 2000.

 Gas Supply

   The following table in BCF provides information with respect to the
Company's sources of supply during the three years 1998-2000.

<TABLE>
<CAPTION>
                                                                Years Ended
                                                                December 31,
                                                               ----------------
                                                               2000  1999  1998
                                                               ----  ----  ----
   <S>                                                         <C>   <C>   <C>
   Natural gas purchases...................................... 18.1  15.8  15.1
   Underground storage withdrawal.............................  4.7   3.1   2.5
   Liquefied natural gas ("LNG") purchases....................  1.4   1.2   1.4
                                                               ----  ----  ----
     Total source of supply................................... 24.2  20.1  19.0
   Company use, unbilled and other............................ (3.8) (1.3) (1.4)
                                                               ----  ----  ----
     Total sales.............................................. 20.4  18.8  17.6
                                                               ====  ====  ====
</TABLE>

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

   The vast majority of 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. 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
                                                           BCF
                                                       ------------ Expiration
                        Pipeline                       Daily Annual   Dates
                        --------                       ----- ------ ----------
   <S>                                                 <C>   <C>    <C>
   Algonquin Gas Transmission Company ("Algonquin")... .046   14.7  2001-2012
   Tennessee Gas Pipeline Company ("Tennessee")....... .072   26.3  2003-2013
                                                       ----   ----
                                                       .118   41.0
                                                       ====   ====
</TABLE>

                                       2
<PAGE>

   In 1999, the Company restructured its long-term capacity contracts on
Tennessee Gas Pipeline. As a result, no contract expires on Tennessee before
2003. Less than 1% of the Company's capacity on Algonquin expires in 2001. In
addition, the Company has firm capacity contracts on interstate pipelines
upstream of 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 3.6 BCF and peak day deliverability of .041 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 affiliates, Boston 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 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.

   The Company has two agreements with Distrigas of Massachusetts Corporation
that expire on October 31, 2001, which allow the Company to purchase up to
10,000 Dekatherms ("Dth") per day for 151 days and 5,000 Dth per day for 365
days of liquefied natural gas ("LNG") in either liquid or vapor form.

   Peak day firm throughput in BCF was 0.126 in 2000, 0.106 in 1999 and 0.093
in 1998 for the Company's Merrimack Valley service area and 0.087 in 2000,
0.069 in 1999 and 0.060 in 1998 for the Company's Cape Cod service area. 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's Merrimack Valley service area has on-system LNG and
propane air facilities which have an aggregate sendout capacity of
approximately .080 BCF per day. The Company also operates on-system facilities
in the Cape Cod service area capable of providing approximately .036 BCF per
day. 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
semiannual 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 for ratemaking purposes, the Company recovers
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.

   In connection with the acquisition by Eastern Enterprises in 1999, on July
15, 1999, the Department approved the merger and rate plan, resulting in a
2.2% reduction in the total burner-tip price paid by the Company's firm sales
customers in the first full year following the merger and a ten-year freeze of
base rates. The base rate freeze is subject only to certain exogenous factors,
such as changes in tax laws, accounting changes, or regulatory, judicial, or
legislative changes. The Office of the Attorney General appealed the
Department's order to the Supreme Judicial Court, which appeal is still
pending. Due to the length of the base rate freeze, the Company discontinued
its application of Statement of Financial Accounting Standards ("SFAS") No.
71, as described in Note 1 of Notes to Consolidated Financial Statements.

                                       3
<PAGE>

   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

   After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand-side management ("DSM") programs, the Department ruled
in November 1999 that effective for filings for the twelve-month period
beginning May 1, 1999, the Company may recover lost margins for only four
years post the installation of DSM measures. This ruling changes the
Department's previous approved calculation method. However, based on the
Department's order approving the merger and rate plan, the Company has
petitioned the Department for recovery of the resulting reduction in lost
margins as an exogenous adjustment. The Office of the Attorney General has
opposed the Company's petition for recovery of the reduction in lost margins
as an exogenous adjustment. This proceeding is currently in the briefing phase
and the Company can not predict the outcome of this pending proceeding.

 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 unbilled gas costs receivable and is financed
through short-term borrowings. Short-term borrowings are also required from
time to time to finance normal business operations. As a result of these
factors, short-term borrowings are generally highest during the late fall and
early winter.

 Environmental Matters

   The Company has or shares responsibility under applicable environmental law
for the remediation of one former manufactured gas plant ("MGP") site, related
satellite disposal sites, one non-MGP site and one federal superfund site.
Information with respect to the remediation of MGP related 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, 2000, the Company had approximately 300 employees, 65%
of whom are organized in local unions with which the Company has collective
bargaining agreements that expire in 2002 and 2003.

                                       4
<PAGE>

Item 2. Properties.

   The Company has two principal operations centers and two principal LNG
storage facilities. One of the storage facilities is located in Tewksbury,
Massachusetts and has a capacity of approximately 1.0 BCF and the other is
located in South Yarmouth, Massachusetts and has a capacity of approximately
 .18 BCF. In addition, the Company owns a 36,000 square foot facility located
in Lowell, Massachusetts used for administrative purposes.

   On December 31, 2000, the Company's distribution system included
approximately 3,200 miles of gas mains, 143,000 services and 164,000 active
customer meters.

   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 2000, the Company's capital expenditures were approximately $19 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 $26
million for similar purposes in 2001.

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 2000.

                                       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.

   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 ("Eastern"), a wholly-owned subsidiary of KeySpan
Corporation ("KeySpan"), is the holder of record of all of the outstanding
common equity securities of the Company. Dividends on such common equity
amounted to $6.0 million and $8.7 million for 2000 and 1999, respectively.

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

 Period from November 8, 2000 through December 31, 2000

   Weather for this period was 13% colder than normal. As a result of the
merger with KeySpan, this period includes amortization of goodwill of $1.6
million and $2.3 million of interest and debt issuance costs on the $250
million advance from KeySpan.

 Period from January 1, 2000 through November 7, 2000

   Weather for the period was 2% colder than normal. As a result of the merger
with KeySpan, the Company recorded merger-related expenses of approximately
$8.8 million consisting primarily of separation payments to officers, payment
of vested stock options and other compensation related matters.

   This period includes a restructuring charge of $7.0 million related to the
Company's exit of the gas appliance rental and service business. The charge
includes $5.1 million to write down to fair value the equipment used in the
rental business and $1.2 million for employee severance and termination
benefits associated with the service business. The remaining $0.7 million is
associated with the disposal of inventory and other related costs.

 1999 Compared to 1998

   Weather for the four months ended December 1999 was 7% warmer than normal.
As a result of the merger with Eastern, the four months ended December 1999
included amortization of goodwill of $2.0 million and $1.6 million of interest
on the $100 million advance from Eastern.

   Weather for the eight months ended August 1999 was 5% warmer than normal.
The eight months ended August 1999 included merger-related costs of $3.8
million incurred by the Company prior to the merger with Eastern.

FORWARD-LOOKING INFORMATION

   This Annual Report on Form 10-K contains certain "forward-looking
statements" concerning projected future financial performance, expected plans
or future operations. The Company cautions that actual results and
developments may differ materially from such projections or expectations.

   Investors should be aware of important factors that could cause actual
results to differ materially from forward-looking projections or expectations
contained herein. These factors include, but are not limited to: the

                                       7
<PAGE>

effect of strategic initiatives on earnings and cash flow, the impact of any
merger-related activities, the ability to successfully integrate natural gas
distribution operations, temperatures above or below normal, changes in
economic conditions, including interest rates, regulatory and court decisions
and developments with respect to previously disclosed environmental
liabilities. Most of these factors are difficult to predict accurately and are
generally beyond the control of the Company.

LIQUIDITY AND CAPITAL RESOURCES

   On November 8, 2000, KeySpan Corporate Services, a KeySpan subsidiary,
became an affiliate of the Company, through Eastern's merger 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 KeySpan merger, the Company recorded in November, 2000, a
$250 million advance payable to KeySpan. A $100 million of this advance was
previously owed to Eastern. Interest charges equal 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 2001 to be approximately $26
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 2001
capital expenditures, working capital requirements, 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
semiannual 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, for ratemaking purposes, the Company recovers
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.

   In connection with the acquisition by Eastern Enterprises in 1999, on July
15, 1999, the Department approved the merger and rate plan, resulting in a
2.2% reduction in the total burner-tip price paid by the Company's firm sales
customers in the first full year following the merger and a ten-year freeze of
base rates. The base rate freeze is subject only to certain exogenous factors,
such as changes in tax laws, accounting changes, or regulatory, judicial, or
legislative changes. The Office of the Attorney General appealed the
Department's order to the Supreme Judicial Court, which appeal is still
pending. Due to the length of the base rate freeze, the Company discontinued
its application of Statement of Financial Accounting Standards ("SFAS") No.
71, as described in Note 1 of Notes to Consolidated Financial Statements.

   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

                                       8
<PAGE>

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.

   After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand-side management ("DSM") programs, the Department ruled
in November 1999 that effective for filings for the twelve-month period
beginning May 1, 1999, the Company may recover lost margins for only four
years past the installation of DSM measures. This ruling changes the
Department's previous approved calculation method. However, based on the
Department's order approving the merger and rate plan, the Company has
petitioned the Department for recovery of the resulting reduction in lost
margins as an exogenous adjustment. The Office of the Attorney General has
opposed the Company's petition for recovery of the reduction in lost margins
as an exogenous adjustment. This proceeding is currently in the briefing phase
and the Company can not predict the outcome of this pending proceeding.

 Environmental Matters

   The Company has or shares responsibility under applicable environmental law
for the remediation of one former manufactured gas plant ("MGP") site, related
satellite disposal sites, one non-MGP site and one federal superfund site.
Information with respect to the remediation of MGP related sites may be found
in Note 9 of Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.

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.

                                       9
<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.

                                       10
<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.

<TABLE>
 <C>  <S>
  2   Agreement and Plan of Reorganization by and between Eastern Enterprises
      and Colonial Gas Company dated as of October 17, 1998, filed as Exhibit
      2.1 to the Registrant's Form 8-K Report dated October 21, 1998.*

  3.1 Restated Articles of Organization for Colonial Gas Company dated August
      5, 1999, filed as Exhibit 3.1 to the Registrant's Annual Report on Form
      10-K for the fiscal year ended December 31, 1999.*

  3.2 By-Laws of Colonial Gas Company dated August 5, 1999, filed as Exhibit
      3.2 to the Registrant's Annual Report on Form 10-K for the fiscal year
      ended December 31, 1999.*

  4.1 Second Amended and Restated First Mortgage Indenture dated as of June 1,
      1992, filed as Exhibit 4(b)
      to Form 10-Q of the Registrant for the quarter ended June 30, 1992.*

  4.2 First Supplemental Indenture dated as of June 15, 1992, filed as Exhibit
      4(c) to Form 10-Q of the Registrant for the quarter ended June 30, 1992.*

  4.3 Second Supplemental Indenture dated as of September 27, 1995, filed as
      Exhibit 4(c) to the Registrant's Annual Report on Form 10-K for the
      fiscal year ended December 31, 1995.*

  4.4 Amendment to Second Supplemental Indenture dated as of October 12, 1995,
      filed as Exhibit 4(d) to the Registrant's Annual Report on Form 10-K for
      the fiscal year ended December 31, 1995.*

  4.5 Third Supplemental Indenture dated as of December 15, 1995, filed as
      Exhibit 4(f) to the Registrant's Form S-3 Registration Statement dated
      January 5, 1998.*

  4.6 Fourth Supplemental Indenture dated as of March 1, 1998, filed as Exhibit
      4(l) to the Registrant's Form 10-Q for the quarter ended March 31, 1998.*

  4.7 Utility Money Pool Agreement. (Filed herewith).

 10.2 Gas Transportation Contract for Firm Reserved Service with Iroquois,
      dated February 7, 1991, filed as Exhibit 10(v) to the Registrant's Annual
      Report on Form 10-K for the fiscal year ended December 31, 1990.*

 10.3 Service Agreement between Algonquin Gas Transmission Company and Colonial
      Gas Company (under Rate Schedule AFT-E), dated June 1, 1993, filed as
      Exhibit 10(p) to the Registrant's Annual Report on Form 10-K for the
      fiscal year ended December 31, 1993.*

 10.4 Service Agreement between Algonquin Gas Transmission Company and Colonial
      Gas Company (under Rate Schedule AFT-1), dated June 1, 1993, filed as
      Exhibit 10(q) to the Registrant's Annual Report on Form 10-K for the
      fiscal year ended December 31, 1993.*

 10.5 Service Agreement between Algonquin Gas Transmission Company and Colonial
      Gas Company (under Rate Schedule AFT-1), dated June 1, 1993, filed as
      Exhibit 10(r) to the Registrant's Annual Report on Form 10-K for the
      fiscal year ended December 31, 1993.*

 10.6 Service Agreement between Algonquin Gas Transmission Company and Colonial
      Gas Company (under Rate Schedule AFT-1), dated June 1, 1993, filed as
      Exhibit 10(s) to the Registrant's Annual Report on Form 10-K for the
      fiscal year ended December 31, 1993.*

 10.7 Service Agreement between Algonquin Gas Transmission Company and Colonial
      Gas Company (under Rate Schedule AFT-E), dated June 1, 1993, filed as
      Exhibit 10(t) to the Registrant's Annual Report on Form 10-K for the
      fiscal year ended December 31, 1993.*
</TABLE>


                                       11
<PAGE>

<TABLE>
 <C>   <S>
 10.8  Service Agreement between Algonquin Gas Transmission Company and
       Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993,
       filed as Exhibit 10(u) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1993.*

 10.9  Service Agreement between Algonquin Gas Transmission Company and
       Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993,
       filed as Exhibit 10(v) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1993.*

 10.10 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule CDS), dated June 1, 1993,
       filed as Exhibit 10(w) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1993.*

 10.11 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company for 1996 dth per day (under Rate Schedule FT-1),
       dated June 1, 1993, filed as Exhibit 10.11 to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1999.*

 10.12 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule FTS-8), dated June 1, 1993,
       filed as Exhibit 10(y) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1993.*

 10.13 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule FTS-7), dated June 1, 1993,
       filed as Exhibit 10(z) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1993.*

 10.14 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company for 7,918 dth per day (under Rate Schedule FT-1),
       dated June 1, 1993, filed as Exhibit 10.14 to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1999.*

 10.15 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company for 2,222 dth per day (under Rate Schedule FT-1),
       dated June 1, 1993, filed as Exhibit 10.15 to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1999.*

 10.16 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company for 104 dth per day (under Rate Schedule FT-1),
       dated June 1, 1993, filed as Exhibit 10.16 to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1999.*

 10.17 Service Agreement between Algonquin Gas Transmission Company and
       Colonial Gas Company (under Rate Schedule AFT-1), dated August 1, 1993,
       filed as Exhibit 10(ll) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1993.*

 10.18 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
       Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
       1993, filed as Exhibit 10(nn) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1993.*

 10.19 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
       Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
       1993, filed as Exhibit 10(oo) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1993.*

 10.20 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
       Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
       1993, filed as Exhibit 10(pp) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1993.*

 10.21 Service Agreement between CNG Transmission Corporation and Colonial Gas
       Company (under Rate Schedule FTNN), dated October 1, 1993, filed as
       Exhibit 10(rr) to the Registrant's Annual Report on Form 10-K for the
       fiscal year ended December 31, 1993.*

 10.22 Service Agreement between CNG Transmission Corporation and Colonial Gas
       Company (under Rate Schedule GSS), dated October 1, 1993, filed as
       Exhibit 10(ss) to the Registrant's Annual Report on Form 10-K for the
       fiscal year ended December 31, 1993.*

 10.23 Service Agreement between CNG Transmission Corporation and Colonial Gas
       Company (under Rate Schedule GSS-II), contract no. 400009, dated
       November 1, 1998, filed as Exhibit 10.23 to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1999.*
</TABLE>


                                       12
<PAGE>

<TABLE>
 <C>   <S>
 10.24 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule FT-1), dated October 1, 1993,
       filed as Exhibit 10 (uu) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1993.*

 10.25 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
       Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
       1993, filed as Exhibit 10 (vv) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1993.*

 10.26 Service Agreement between National Fuel Gas Supply Corporation and
       Colonial Gas Company (under Rate Schedule EFT), dated October 28, 1993,
       filed as Exhibit 10 (ww) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1993.*

 10.27 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
       Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
       1993, filed as Exhibit 10 (xx) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1993.*

 10.28 Service Agreement between Algonquin Gas Transmission Company and
       Colonial Gas Company (under Rate Schedule AIT-1), dated September 15,
       1993, filed as Exhibit 10 (yy) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1993.*

 10.29 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
       Colonial Gas Company (under Rate Schedule FT-A), dated October 1, 1993,
       filed as Exhibit 10 (zz) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1993.*

 10.30 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule FT-1), dated August 18, 1994,
       filed as Exhibit 10 (kk) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1994.*

 10.31 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule FSS-1), dated August 29, 1994,
       filed as Exhibit 10 (ll) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1994.*

 10.32 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule CDS), dated August 29, 1994,
       filed as Exhibit 10 (mm) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1994.*

 10.33 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule CDS), dated August 29, 1994,
       filed as Exhibit 10 (nn) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1994.*

 10.34 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule SS-1), dated November 30,
       1994, filed as Exhibit 10 (oo) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1994.*

 10.35 Service Agreement between Texas Eastern Transmission Corporation and
       Colonial Gas Company (under Rate Schedule FSS-1), dated November 30,
       1994, filed as Exhibit 10 (pp) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1994.*

 10.36 Letter Agreement between Algonquin Gas Transmission Company and Colonial
       Gas Company, Regarding transfer of transportation entitlements, dated
       March 28, 1994, filed as Exhibit 10 (qq) to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1994.*

 10.37 Service Agreement between Algonquin Gas Transmission Company and
       Colonial Gas Company (under Rate Schedule AFT-1), dated November 1,
       1994, filed as Exhibit 10 (ss) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1994.*

 10.38 Service Agreement between Algonquin Gas Transmission Company and
       Colonial Gas Company (under Rate Schedule AFT-1), dated November 1,
       1994, filed as Exhibit 10 (tt) to the Registrant's Annual Report on Form
       10-K for the fiscal year ended December 31, 1994.*

 10.39 Firm Natural Gas Transportation agreement between Tennessee Gas Pipeline
       and Colonial Gas Company (under Rate Schedule NET-Northeast), dated
       August 1, 1995, filed as Exhibit 10 (qq) to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1995.*
</TABLE>


                                       13
<PAGE>

<TABLE>
 <C>   <S>
 10.40 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
       Colonial Gas Company (under Rate Schedule FT-A), dated June 1, 1995,
       filed as Exhibit 10 (rr) to the Registrant's Annual Report on Form 10-K
       for the fiscal year ended December 31, 1995.*

 10.41 Amendment No. 1 (dated July 1, 1995 to Gas Storage Contract between
       Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate
       Schedule FS), dated December 1, 1994 (which superseded contract dated
       September 1, 1993), filed as Exhibit 10 (ss) to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1995.*

 10.42 Amendment to Gas Transportation Contract for Firm Reserved Service with
       Iroquois Gas Transmission System, L.P., dated September 1, 1995, filed
       as Exhibit 10 (tt) to the Registrant's Annual Report on Form 10-K for
       the fiscal year ended December 31, 1995.*

 10.43 Service Agreement between Algonquin Transmission Company and Colonial
       Gas Company (Under Rate Schedule AFT-1), dated December 1, 1995, filed
       as Exhibit 10 (uu) to the Registrant's Annual Report on Form 10-K for
       the fiscal year ended December 31, 1995.*

 10.44 Service Agreement between Algonquin Gas Transmission Company and
       Colonial Gas Company (under Rate Schedule AFT-1), dated June 23, 2000.
       (Filed herewith).

 10.45 Service Agreement between CNG Transmission Corporation and Colonial Gas
       Company (under Rate Schedule GSS-II), contract No. 300114, dated
       November 1, 1998, filed as Exhibit 10.45 to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1999.*

 10.46 Service Agreement between CNG Transmission Corporation and Colonial Gas
       Company (under Rate Schedule GSS-II), contract No. 300115, dated
       November 1, 1998, filed as Exhibit 10.46 to the Registrant's Annual
       Report on Form 10-K for the fiscal year ended December 31, 1999.*

 10.47 Amended Service Agreement between Texas Eastern Transmission Corporation
       and Colonial Gas Company (under Rate Schedules CDS & FT-1) dated January
       6, 1999, filed as Exhibit 10.47 to the Registrant's Annual Report on
       Form 10-K for the fiscal year ended December 31, 1999.*

 10.48 Redacted Gas Resources Portfolio Management and Gas Sales Agreement
       between Colonial Gas Company and El Paso Energy Marketing Company dated
       September 14, 1999, as amended, filed herewith as Exhibit 10.1 to Form
       10-K of Eastern Enterprises for the year ended December 31, 1999.*

 10.49 Contract Restructuring Agreement between Colonial Gas Company and
       Tennessee Gas Pipeline dated August 2, 1999, filed as Exhibit 10.49 to
       the Registrant's Annual Report on Form 10-K for the fiscal year ended
       December 31, 1999.*

 23a   Consent of Independent Public Accountants.

 23b   Consent of Independent Public Accountants.
</TABLE>

   There were no reports on Form 8-K filed in the Fourth Quarter of 2000.
--------
*  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.

                                      14
<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.

                                          Colonial Gas Company
                                          D/B/A KEYSPAN ENERGY DELIVERY
                                           NEW ENGLAND (Registrant)

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

Date: April 2, 2001

   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 2nd day of April, 2001.

<TABLE>
<CAPTION>
                 Signature                                     Title
                 ---------                                     -----

<S>                                         <C>
             Chester R. Messer              Director and President
___________________________________________
             Chester R. Messer
</TABLE>

                                       15
<PAGE>

                             COLONIAL GAS COMPANY

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

<TABLE>
<S>                                                                <C>
Reports of Independent Public Accountants......................... F-18 and F-19
 Consolidated Statements of Earnings for the Period from November
  8, 2000 through December 31, 2000, Period from January 1, 2000
  through November 7, 2000, Four Months Ended December 31, 1999,
  Eight Months Ended August 31, 1999, and Year Ended December 31,
  1998............................................................      F-2
 Consolidated Balance Sheets as of December 31, 2000 and 1999.....  F-3 and F-4
 Consolidated Statements of Retained Earnings for the Period from
  November 8, 2000 through December 31, 2000, Period from January
  1, 2000 through November 7, 2000, Four Months Ended December 31,
  1999, Eight Months Ended August 31, 1999, and Year Ended
  December 31, 1998...............................................      F-5
 Consolidated Statements of Cash Flows for the Period from
  November 8, 2000 through December 31, 2000, Period from January
  1, 2000 through November 7, 2000, Four Months Ended December 31,
  1999, Eight Months Ended August 31, 1999, and Year Ended
  December 31, 1998 ..............................................      F-6
 Notes to Consolidated Financial Statements.......................  F-7 to F-17
 Interim Financial Information for the Two Years Ended December
  31, 2000 (Unaudited)............................................     F-20
 Schedule for the Period from November 8, 2000 through December
  31, 2000, the Period from January 1, 2000 through November 7,
  2000, and Two Years Ended December 31, 1999:
   Schedule II--Valuation and Qualifying Accounts.................     F-21
</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>

                              COLONIAL GAS COMPANY

                      CONSOLIDATED STATEMENTS OF EARNINGS

<TABLE>
<CAPTION>
                          Period from
                          November 8,    Period from      Four Months
                          2000 through    January 1,         Ended        Eight Months     Year Ended
                          December 31,   2000 through     December 31,        Ended       December 31,
                              2000     November 7, 2000       1999       August 31, 1999      1998
                          ------------ ---------------- ---------------- --------------- ---------------
                                                          (In Thousands)
                                       (Predecessor II) (Predecessor II) (Predecessor I) (Predecessor I)
<S>                       <C>          <C>              <C>              <C>             <C>
Operating revenues......    $61,414        $138,142         $54,098         $122,626        $167,978
Cost of gas sold........     34,106          68,064          26,087           65,320          88,127
                            -------        --------         -------         --------        --------
Operating margin........     27,308          70,078          28,011           57,306          79,851
                            -------        --------         -------         --------        --------
Operating expenses:
  Operations............      4,666          22,531           9,101           19,818          27,793
  Maintenance...........        576           2,950           1,151            4,835           4,794
  Depreciation and
   amortization.........      2,875          11,359           2,857           10,086          13,435
  Amortization of
   goodwill.............      1,556           5,020           2,008              --              --
  Income taxes..........      5,429           1,601           3,406            3,639           7,134
  Taxes, other than
   income...............        830           3,748           1,626            3,861           5,155
  Restructuring charge..        --            7,000             --               --              --
  Merger related
   expenses.............        --            8,795             --             3,788           1,808
                            -------        --------         -------         --------        --------
  Total operating
   expenses.............     15,932          63,004          20,149           46,027          60,119
                            -------        --------         -------         --------        --------
Operating earnings......     11,376           7,074           7,862           11,279          19,732
Other earnings (loss),
 net....................         19             315             237              (20)            485
                            -------        --------         -------         --------        --------
Earnings before interest
 expense................     11,395           7,389           8,099           11,259          20,217
                            -------        --------         -------         --------        --------
Interest expense:
  Long-term debt........      1,422           7,111           2,844            5,689           8,130
  Other, including
   amortization of debt
   expense..............      3,148           7,702           2,569            1,244             604
  Less--Interest during
   construction.........        (31)            (64)            (27)            (194)           (805)
                            -------        --------         -------         --------        --------
  Total interest
   expense..............      4,539          14,749           5,386            6,739           7,929
                            -------        --------         -------         --------        --------
Net earnings (loss).....    $ 6,856        $ (7,360)        $ 2,713         $  4,520        $ 12,288
                            =======        ========         =======         ========        ========
</TABLE>

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

                                      F-2
<PAGE>

                              COLONIAL GAS COMPANY

                          CONSOLIDATED BALANCE SHEETS

                                     ASSETS

<TABLE>
<CAPTION>
                                                           December 31,
                                                     --------------------------
                                                       2000          1999
                                                     --------  ----------------
                                                          (In Thousands)
                                                               (Predecessor II)
<S>                                                  <C>       <C>
Gas plant, at cost.................................. $394,509      $390,447
Construction work-in-progress.......................    7,751         2,914
  Less-Accumulated depreciation..................... (119,564)     (109,628)
                                                     --------      --------
    Net plant.......................................  282,696       283,733
                                                     --------      --------
Current assets:
  Cash..............................................      124           389
  Accounts receivable, less reserves of $2,964 at
   December 31, 2000 and $2,677 at December 31,
   1999.............................................   24,285        15,987
  Accounts receivable--affiliates...................    5,235           --
  Accrued utility margin............................    8,679         8,074
  Unbilled gas costs receivable.....................   47,285        13,803
  Natural gas and other inventories, at average
   cost.............................................   13,246        11,581
  Materials and supplies, at average cost...........    1,709         2,277
  Current income taxes..............................      --          4,182
  Prepaid expenses..................................      262           330
                                                     --------      --------
    Total current assets............................  100,825        56,623
                                                     --------      --------
Other assets:
  Excess of cost over fair value of acquired net
   assets, less amortization........................  371,850       239,045
  Deferred charges and other assets.................    4,077         4,646
                                                     --------      --------
    Total other assets..............................  375,927       243,691
                                                     --------      --------
    Total assets.................................... $759,448      $584,047
                                                     ========      ========
</TABLE>


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

                                      F-3
<PAGE>

                              COLONIAL GAS COMPANY

                          CONSOLIDATED BALANCE SHEETS

                         CAPITALIZATION AND LIABILITIES

<TABLE>
<CAPTION>
                                                            December 31,
                                                      -------------------------
                                                        2000         1999
                                                      -------- ----------------
                                                           (In Thousands)
                                                               (Predecessor II)
<S>                                                   <C>      <C>
Capitalization:
  Common stockholder's investment--
   Common stock, $1 par value--
   Authorized and outstanding--100 shares at December
    31, 2000 and 1999................................ $    --      $    --
  Amounts in excess of par value.....................  203,558      225,667
  Retained earnings..................................    6,856          229
                                                      --------     --------
    Total common stockholder's investment............  210,414      225,896
Long-term obligations, less current portion..........  120,621      121,021
                                                      --------     --------
    Total capitalization.............................  331,035      346,917
Advance from KeySpan.................................  250,000          --
Advance from Eastern.................................      --       100,000
                                                      --------     --------
    Total capitalization and advances................  581,035      446,917
                                                      --------     --------
Current liabilities:
  Current portion of long-term obligations...........      572          646
  Notes payable--utility pool........................   47,209          --
  Notes payable--utility pool gas inventory
   financing.........................................   19,216          --
  Notes payable......................................      --        29,000
  Gas inventory financing............................      --        15,009
  Accounts payable...................................   38,765       16,578
  Accounts payable--affiliates.......................    6,486       17,916
  Accrued income taxes...............................      291          --
  Accrued interest...................................    4,263        2,936
  Customer deposits..................................      738          644
  Refunds due customers..............................    2,681        5,331
  Other..............................................      781          389
                                                      --------     --------
    Total current liabilities........................  121,002       88,449
                                                      --------     --------
Reserves and deferred credits:
  Deferred income taxes..............................   36,641       32,276
  Unamortized investment tax credits.................    2,605        2,811
  Postretirement benefits obligation.................    5,972        5,136
  Other..............................................   12,193        8,458
                                                      --------     --------
    Total reserves and deferred credits..............   57,411       48,681
                                                      --------     --------
    Total capitalization and liabilities............. $759,448     $584,047
                                                      ========     ========
</TABLE>

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

                                      F-4
<PAGE>

                              COLONIAL GAS COMPANY

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

<TABLE>
<CAPTION>
                         Period from
                         November 8,    Period from      Four Months
                         2000 through    January 1,         Ended        Eight Months     Year Ended
                         December 31,   2000 through     December 31,        Ended       December 31,
                             2000     November 7, 2000       1999       August 31, 1999      1998
                         ------------ ---------------- ---------------- --------------- ---------------
                                                         (In Thousands)
                                      (Predecessor II) (Predecessor II) (Predecessor I) (Predecessor I)
<S>                      <C>          <C>              <C>              <C>             <C>
Balance at beginning of
 period.................    $  --              229         $   --           $36,173        $ 35,924
  Net earnings (loss)...     6,856          (7,360)          2,713            4,520          12,288
  Cash dividends on
   common stock.........       --           (6,039)         (2,484)          (6,255)        (12,039)
                            ------        --------         -------          -------        --------
Balance at end of
 period.................    $6,856        $(13,170)        $   229          $34,438        $ 36,173
                            ======        ========         =======          =======        ========
</TABLE>



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

                                      F-5
<PAGE>

                              COLONIAL GAS COMPANY

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                         Period from
                         November 8,    Period from      Four Months
                         2000 through    January 1,         Ended        Eight Months     Year Ended
                         December 31,   2000 through     December 31,        Ended       December 31,
                             2000     November 7, 2000       1999       August 31, 1999      1998
                         ------------ ---------------- ---------------- --------------- ---------------
                                                         (In Thousands)
                                      (Predecessor II) (Predecessor II) (Predecessor I) (Predecessor I)
<S>                      <C>          <C>              <C>              <C>             <C>
Cash flows from
 operating activities:
 Net earnings (loss)....   $  6,856       $ (7,360)        $  2,713        $  4,520        $ 12,288
 Adjustments to
  reconcile net earnings
  to cash provided by
  operating activities:
 Depreciation and
  amortization..........      4,431         16,379            4,865          10,086          14,764
 Deferred taxes.........      4,724          4,194            2,198          (2,751)          2,890
 Other changes in
  assets and
  liabilities:
  Accounts receivable...     (7,986)        (6,122)          (4,548)          1,802           5,344
  Accrued utility
   margin...............     (7,955)         7,350           (7,420)          7,222            (459)
  Accounts payable--
   affiliates...........      4,859        (15,714)          15,084           2,832             --
  Inventories...........      8,752         (9,850)           1,120             640             247
  Deferred gas costs....    (21,475)       (12,006)         (13,888)         18,280           1,071
  Accounts payable......     10,548         11,639            5,666          (1,274)         (3,488)
  Accrued income
   taxes................      1,333          3,853           (5,200)        (10,708)         (1,897)
  Other.................      2,014          3,929           (7,481)         22,884          (1,317)
                           --------       --------         --------        --------        --------
   Cash (used for)
    provided by
    operating
    activities..........      6,101         (3,708)          (6,891)         53,533          29,443
                           --------       --------         --------        --------        --------
Cash flows from
 investing activities:
 Capital expenditures...     (6,943)       (12,092)          (7,105)        (12,715)        (31,457)
                           --------       --------         --------        --------        --------
Cash flows from
 financing activities:
 Changes in notes
  payable, net..........       (191)        18,400           10,000         (33,000)          2,600
 Changes in inventory
  financing.............      1,031          3,176            4,139          (3,255)           (770)
 Issuance of long-term
  debt, net of issuance
  cost..................        --             --               --              --           39,116
 Retirement of long-term
  debt, including
  premiums..............        --             --               --             (102)        (30,568)
 Issuance of common
  stock.................        --             --               --            1,399           6,541
 Cash dividends paid on
  common stock..........        --          (6,039)          (2,484)         (6,255)        (12,039)
                           --------       --------         --------        --------        --------
   Cash provided by
    (used for) financing
    activities..........        840         15,537           11,655         (41,213)          4,880
                           --------       --------         --------        --------        --------
Increase (decrease) in
 cash...................         (2)          (263)          (2,341)           (395)          2,866
Cash at beginning of
 period.................        126            389            2,730           3,125             259
                           --------       --------         --------        --------        --------
Cash at end of period...   $    124            126         $    389        $  2,730        $  3,125
                           ========       ========         ========        ========        ========
Supplemental disclosure
 of cash flow
 information:
 Cash paid (refunded)
  during the year for:
   Interest, net of
    amounts
    capitalized.........   $    623       $ 14,206         $  1,657        $  8,434        $ 10,229
                           ========       ========         ========        ========        ========
   Income taxes.........   $    --        $ (6,921)        $  4,376        $  3,595        $  7,238
                           ========       ========         ========        ========        ========
</TABLE>

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

                                      F-6
<PAGE>

                             COLONIAL GAS COMPANY

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Accounting Policies

 General

   Colonial 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 24
municipalities located northwest of Boston and on Cape Cod. The Company is a
wholly-owned subsidiary of Eastern Enterprises ("Eastern") and an indirect
wholly-owned subsidiary of KeySpan Corporation ("KeySpan").

 Basis of Presentation

   The consolidated financial statements include the accounts of the Company
and its affiliate, Massachusetts Fuel Inventory Trust (through December 31,
2000) and its wholly-owned subsidiary, Transgas Inc. (through August 31,
1999). Transgas ceased to be a subsidiary of Colonial Gas Company and became a
subsidiary of Eastern upon closing of the Eastern merger discussed below. All
material intercompany balances and transactions between the Company and its
subsidiary have been eliminated in consolidation.

   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.

 KeySpan Merger

   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. Consistent with the Eastern merger, 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. The allocation of the purchase price remains subject to
adjustment upon final valuation of certain acquired balances of the Company.
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 $139
million has been recorded as an asset and is being amortized over a period of
40 years. The push-down accounting resulted in a decrease to equity of $8.9
million and the recording of a $250 million advance from KeySpan, $100 million
of which was previously owed to Eastern.

 Eastern Merger

   On August 31, 1999, the Company completed a merger with Eastern in a
transaction with an enterprise value of approximately $474 million. In
effecting the transaction, Eastern paid $150 million in cash, net of cash
acquired and including transaction costs, issued approximately 4.2 million
shares of common stock valued at $186 million and assumed $138 million of
debt.

   The merger was accounted for using the purchase method of accounting for
business combinations. The purchase price was allocated to the net assets
acquired based on their fair value. The historical cost basis of the Company's
assets and liabilities, with the exception of the adjustments described below,
was determined to represent the fair value due to the existence of a
regulatory-approved rate plan based upon the recovery of historical costs and
a fair return thereof. Most of the operations of the Company have been
integrated into the operations of its affiliate, Boston Gas, an indirect
wholly-owned subsidiary of KeySpan.

                                      F-7
<PAGE>

                             COLONIAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


(1) Accounting Policies (Continued)

   In connection with the merger, the Department of Telecommunications and
Energy (the "Department") approved a rate plan resulting in a ten-year freeze
of base rates at current levels. Due to the length of the base rate freeze,
the Company was required to discontinue its application of Statement of
Financial Accounting Standards ("SFAS") No. 71 "Accounting for the Effects of
Certain Types of Regulation".

   Accordingly, as of the merger, the Company assigned no value to regulatory
assets of approximately $18 million, consisting principally of deferred demand
side management program costs, deferred environmental costs and unrecovered
deferred income taxes.

   The excess of consideration over the fair value of the assets acquired of
$241 million was recorded as goodwill, which was being amortized on a
straight-line basis over a 40-year period. Of the $241 million, $141 million
was recorded as an increase to common equity and $100 million as an advance
from Eastern.

 Regulation

   The Company is regulated as to rates, accounting and other matters by the
Department.

   For the periods prior to the merger with Eastern and the approved rate
plan, the accounting policies conformed to generally accepted accounting
principles as applied to regulated public utilities and reflected the effects
of the ratemaking process in accordance with SFAS No. 71. Under SFAS No. 71,
the Company was allowed to defer certain costs that otherwise would be
expensed in recognition of the ability to recover them in future rates. As
described above, the Company discontinued application of SFAS No. 71 in
connection with the Department's approval of the merger of the Company with
Eastern.

 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 Unbilled Gas Costs Receivable

   The cost of gas adjustment clause ("CGAC") requires the Company to semi-
annually 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.
In its order of August 14, 1998, the Department modified the CGAC to recover
the gas cost portion of the Company's bad debt write-offs effective November
1, 1998. The order also approved a local distribution adjustment clause
("LDAC") to recover the amortization of all environmental response costs
associated with former manufactured gas plant ("MGP") sites, costs related to
the Company's various demand side management programs and other specified
costs from the Company's firm sales and transportation customers. These costs
were previously recovered through the CGAC. Upon the discontinuance of the
application of SFAS No. 71, the Company records amounts recoverable under the
LDAC as revenue when billed to 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 3.7% for all periods
presented.


                                      F-8
<PAGE>

                             COLONIAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


(1) Accounting Policies (Continued)

   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

   The Company adopted SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities" on January 1, 2001, which at that time had no effect
on the Company's financial statements, since the Company had no outstanding
derivatives at December 31, 2000.

   The Financial Accounting Standards Board ("FASB") recently issued a
revision to its Exposure Draft ("ED") on "Business Combinations and Intangible
Assets". In the revised ED, the FASB concluded that the amortization of
goodwill will no longer be required. Instead, companies will need to perform
yearly impairment tests on the recorded amount of goodwill and determine
whether an impairment charge is necessary. The comment deadline on the revised
ED was March 16, 2001 and we believe the FASB will finalize its deliberations
on goodwill amortization in the third or fourth quarter of 2001. Goodwill
amortization for 2001 is estimated to be approximately $9,000,000. Depending
on the timing of the final statement, the Company may realize a significant
benefit to earnings in 2001 if the Company is required to discontinue the
amortization of goodwill. Such enhancement to earnings will not affect cash
flow.

 Reclassifications

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

(2) Income Taxes

   Since its acquisition by Eastern, the Company has been a member of an
affiliated group of companies that files a consolidated federal income tax
return. The Company's effective income tax rate was 44% for the period from
November 8, 2000 through December 31, 2000, 56% for the four months ended
December 31, 1999, 45% for the eight months ended August 31, 1999 and 37% in
1998. State taxes and the nondeductibility of goodwill amortization associated
with the Eastern and KeySpan mergers, represent the majority of the difference
between the effective rate and the federal income rate of 35% for 2000 and
1999 and state income taxes represent the majority of the difference for 1998.
For the period from January 1 through November 7, 2000, the effective tax rate
was incalculable as there was income tax expense even though the Company had a
loss. This was due to the non-deductibility of goodwill amortization and
certain merger costs.

                                      F-9
<PAGE>

                             COLONIAL 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
                           November 8    Period from      Four Months
                            through       January 1,         Ended        Eight Months     Year Ended
                          December 31,     through        December 31,        Ended       December 31,
                              2000     November 7, 2000       1999       August 31, 1999      1998
                          ------------ ---------------- ---------------- --------------- ---------------
                                                          (In Thousands)
                                       (Predecessor II) (Predecessor II) (Predecessor I) (Predecessor I)
<S>                       <C>          <C>              <C>              <C>             <C>
Current--
  Federal...............     $  588        $(2,166)          $1,028          $ 5,344         $3,827
  State.................        117           (427)             180            1,046            718
                             ------        -------           ------          -------         ------
    Total Current
     Provision..........        705         (2,593)           1,208            6,390          4,545
                             ------        -------           ------          -------         ------
Deferred--
  Federal...............      3,942          3,476            1,800           (2,328)         2,387
  State.................        782            718              398             (423)           503
                             ------        -------           ------          -------         ------
    Total Deferred
     Provision..........      4,724          4,194            2,198           (2,751)         2,890
                             ------        -------           ------          -------         ------
Amortization of
 investment tax credit..        --             --               --               --            (301)
                             ------        -------           ------          -------         ------
Provision for income
 taxes..................     $5,429        $ 1,601           $3,406          $ 3,639         $7,134
                             ======        =======           ======          =======         ======
</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. Income tax
credits are deferred and credited to income over the lives of the property
giving rise to such credits.

   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, 2000 and 1999 are as follows:

<TABLE>
<CAPTION>
                                                          December 31,
                                                    --------------------------
                                                      2000          1999
                                                    --------  ----------------
                                                         (In Thousands)
                                                              (Predecessor II)
<S>                                                 <C>       <C>
Assets:
    Total deferred tax assets...................... $ 13,437      $  1,077
                                                    --------      --------
Liabilities:
  Accelerated Depreciation.........................  (35,296)      (37,813)
  Deferred Gas Costs...............................  (12,389)         (748)
  Other............................................   (7,960)        5,683
                                                    --------      --------
    Total deferred tax liabilities.................  (55,645)      (32,878)
                                                    --------      --------
    Total net deferred taxes....................... $(42,208)     $(31,801)
                                                    ========      ========
Deferred taxes are reflected in the balance sheet
 as follows:
  Accrued income taxes (current deferred).......... $ (5,567)     $    475
  Deferred income taxes (long-term)................  (36,641)      (32,276)
                                                    --------      --------
    Total.......................................... $(42,208)     $(31,801)
                                                    ========      ========
</TABLE>

                                     F-10
<PAGE>

                             COLONIAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


(3) Debt

 Long-term Obligations

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

<TABLE>
<CAPTION>
                                                           December 31,
                                                     --------------------------
                                                       2000          1999
                                                     --------  ----------------
                                                          (In Thousands)
                                                               (Predecessor II)
<S>                                                  <C>       <C>
First Mortgage Bonds:
  8.80%, Series CH, due 2022........................ $ 25,000      $ 25,000
  6.38%-6.94%, Medium-Term Notes, Series A, due
   2008-2027........................................   65,000        65,000
  5.50%-6.86%, Medium-Term Notes, Series B, due
   2003-2028........................................   30,000        30,000
Capital lease obligations (Note 5)..................    1,193         1,667
Less current portion................................     (572)         (646)
                                                     --------      --------
                                                     $120,621      $121,021
                                                     ========      ========
</TABLE>

   Bonds of $10,000,000 are due in 2003. Bonds of $15,000,000 due in 2027 can
be redeemed by the holder in 2002. Bonds of $20,000,000 due in 2025 can be
redeemed by the holder in 2005. Bonds of $20,000,000 due in 2028 can be
redeemed by the holder in 2008.

   The first mortgage bonds are collateralized by utility property. The
Company's first mortgage bond indenture includes, among other provisions,
limitations on the issuance of long-term debt, leases and the payment of
dividends from retained earnings.

   Annual maturities of capital lease obligations are $572,000, $437,000,
$153,000, $31,000 and $0 for 2001 through 2005, respectively.

 Utility Money Pool Borrowings

   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,
2000, the Company had outstanding borrowings of $47,209,000 and $19,216,000
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 by KeySpan Corporate Services in obtaining the required funds. All
costs related to the gas inventory borrowings are recoverable from customers
through the CGAC. The average rate on these borrowings was 6.92%.

 Advance from KeySpan Corporation

   As part of the merger, the Company recorded in November, 2000 a $250
million advance payable to KeySpan. A $100 million of the advance was
previously owed to Eastern and is reflected on the Balance Sheet at December
31, 1999. Interest charges equal interest incurred by KeySpan on debt
borrowings issued by KeySpan and recorded on the books of the Company. The
interest rate on these borrowings is 7.625%. 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-11
<PAGE>

                             COLONIAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


(4) Retiree Benefits

   Effective January 1, 1999, the Company adopted SFAS No. 132, "Employers'
Disclosures about Pensions and Other Post-retirement Benefits," which revises
prior disclosure requirements. Previous information has been restated to
conform to the current presentation.

 Pension Plans

   The Company has defined benefit pension plans covering substantially all
employees. These include two qualified union plans, one qualified plan for
non-union employees, and various unqualified individual retirement agreements
covering certain key employees and retirees. The Company's funding policy for
the qualified plans is to contribute annually an amount at least equal to the
normal cost plus a 30-year amortization of the unfunded actuarially calculated
accrued liability. The net periodic pension cost was as follows:

<TABLE>
<CAPTION>
                          Period from
                          November 8,    Period from      Four Months
                            through       January 1,         Ended        Eight Months     Year Ended
                          December 31,     through        December 31,        Ended       December 31,
                              2000     November 7, 2000       1999       August 31, 1999      1998
                          ------------ ---------------- ---------------- --------------- ---------------
                                                          (In Thousands)
                                       (Predecessor II) (Predecessor II) (Predecessor I) (Predecessor I)
<S>                       <C>          <C>              <C>              <C>             <C>
Service cost............     $ 184         $   643          $   243          $   850         $ 1,220
Interest cost on
 projected benefits
 obligations............       679           3,092            1,239            2,447           3,492
Expected return on plan
 assets.................      (700)         (3,197)          (1,302)          (2,977)         (4,170)
Amortization of prior
 service cost...........       --              --               --                97             161
Amortization of
 transitional
 obligation.............       --              --               --               238             357
Recognized actuarial
 loss...................       --              --               --                96             107
Curtailment.............       --              --               --               295             --
                             -----         -------          -------          -------         -------
Total net pension cost..     $ 163         $   538          $   180          $ 1,046         $ 1,167
                             =====         =======          =======          =======         =======
</TABLE>

 Postretirement Life and Health Care

   The Company has a postretirement benefit plan that covers substantially all
employees. The plan provides medical, dental and life insurance benefits. The
plan is contributory for retirees, with respect to postretirement medical and
dental benefits; the plan is noncontributory with respect to life insurance
benefits.

   Beginning in 1990, the Company has funded a portion of these costs through
the combination of trusts under Section 501(c)(9) and Section 401(h) of the
Internal Revenue Code.

   Net periodic expense for postretirement benefits other than pensions was as
follows:

<TABLE>
<CAPTION>
                          Period from
                          November 8,    Period from      Four Months
                            through       January 1,         Ended        Eight Months     Year Ended
                          December 31,     through        December 31,        Ended       December 31,
                              2000     November 7, 2000       1999       August 31, 1999      1998
                          ------------ ---------------- ---------------- --------------- ---------------
                                                          (In Thousands)
                                       (Predecessor II) (Predecessor II) (Predecessor I) (Predecessor I)
<S>                       <C>          <C>              <C>              <C>             <C>
Service cost............      $ 81          $ 107            $  39            $  94           $ 138
Interest cost on
 accumulated benefits
 obligations............       161            649              247              400             534
Expected return on plan
 assets.................       (76)          (304)            (127)            (292)           (412)
Amortization of
 transition obligation..       --             --               --               166             249
Recognized actual gain..       --             --               --               --              --
Curtailment.............       --             --               --               308             --
                              ----          -----            -----            -----           -----
Total net retiree health
 care cost..............      $166          $ 452            $ 159            $ 676           $ 509
                              ====          =====            =====            =====           =====
</TABLE>

                                     F-12
<PAGE>

                             COLONIAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


(4) Retiree Benefits (Continued)

   The tables above do not reflect retirement enhancements for pension and
health care of $2,667,000 and $33,000, respectively for the eight months ended
August 31, 1999.

   The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's pension plans and
amounts recorded in the Company's balance sheet as of December 31, 2000,
November 7, 2000, December 31, 1999 and August 31, 1999. Actuarial measurement
dates are December 31, 2000, November 7, 2000, October 1, 1999 and August 31,
1999, respectively.

<TABLE>
<CAPTION>
                          Period from
                           November 8    Period from      Four Months
                            through       January 1,         Ended        Eight Months
                          December 31,     through        December 31,        Ended
                              2000     November 7, 2000       1999       August 31, 1999
                          ------------ ---------------- ---------------- ---------------
                                                  (In Thousands)
                                       (Predecessor II) (Predecessor II) (Predecessor I)
<S>                       <C>          <C>              <C>              <C>
Pensions
Change in benefit
 obligation
Balance at beginning of
 period.................    $ 55,503       $52,986          $53,805          $53,132
Service cost............         183           643              243              850
Interest cost...........         691         3,079            1,239            2,447
Plan amendments.........         --            --               --               --
Curtailment loss........         --            --               --               557
Special termination
 benefits...............         --            --               --             2,667
Benefits paid...........        (475)       (3,370)          (1,152)          (2,045)
Subsidiary spun-off.....         --            --               --            (2,557)
Actuarial (gain) loss...       4,409         2,165           (1,149)          (1,246)
                            --------       -------          -------          -------
Balance at end of
 period.................    $ 60,311       $55,503          $52,986          $53,805
                            ========       =======          =======          =======
Change in plan assets
Fair value, beginning of
 period.................    $ 49,971       $48,484          $50,055          $51,839
Actual return on plan
 assets.................        (520)        4,318             (486)           1,564
Employer contributions..          23           539               67              569
Benefits paid...........        (475)       (3,370)          (1,152)          (2,045)
Subsidiary spun-off.....         --            --               --            (1,872)
                            --------       -------          -------          -------
Fair value at end of
 period.................    $ 48,999       $49,971          $48,484          $50,055
                            ========       =======          =======          =======
Reconciliation of funded
 status
Funded status...........    $(11,312)      $(5,532)         $(4,502)         $(3,750)
Contributions for fourth
 quarter................         --            --               158              --
Unrecognized actuarial
 loss...................       5,641         3,000              640              --
Unrecognized transition
 obligation.............         --            --               --               --
Unrecognized prior
 service................         --            --               --               --
                            --------       -------          -------          -------
Net amount recognized at
 end of period..........    $ (5,671)      $(2,532)         $(3,704)         $(3,750)
                            ========       =======          =======          =======
Amounts recognized in
 balance sheet
Prepaid benefit cost....    $     59       $    73          $   130          $    92
Accrued benefit
 liability..............      (5,730)       (2,605)          (3,904)          (3,842)
Intangible asset........         --            --               --               --
Accumulated other
 comprehensive income...         --            --                70              --
                            --------       -------          -------          -------
Net amount..............    $ (5,671)      $(2,532)         $(3,704)         $(3,750)
                            ========       =======          =======          =======
</TABLE>

                                     F-13
<PAGE>

                             COLONIAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


(4) Retiree Benefits (Continued)

   Assets of the employee benefit plans are invested in domestic and
international equities, domestic and international fixed income securities,
real estate and other short-term debt instruments.

   The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's post-retirement
life and health benefit plans and amounts recorded in the Company's balance
sheet as of December 31, 2000, November 7, 2000, December 31, 1999 and August
31, 1999. Actuarial measurement dates are December 31, 2000, November 7, 2000,
October 1, 1999 and August 31, 1999, respectively.

<TABLE>
<CAPTION>
                          Period from
                           November 8    Period from
                            through       January 1,      Four Months     Eight Months
                          December 31, through November  Ended December       Ended
                              2000         7, 2000          31, 1999     August 31, 1999
                          ------------ ---------------- ---------------- ---------------
                                                  (In Thousands)
                                       (Predecessor II) (Predecessor II) (Predecessor I)
<S>                       <C>          <C>              <C>              <C>
Healthcare
Change in benefit
 obligation
Balance at beginning of
 period.................    $11,396        $10,761          $10,235          $ 8,558
Service cost............         81            108               39               94
Interest cost...........        161            649              247              400
Plan amendments.........        --             --               --               --
Curtailment loss........        --             --               --              (270)
Special termination
 benefits...............        --             --               --                33
Benefits paid...........        (49)          (545)             (49)            (278)
Subsidiary spun-off.....        --             --               --              (586)
Actuarial (gain) loss...      1,230            423              289            2,284
                            -------        -------          -------          -------
Balance at end of
 period.................    $12,819        $11,396          $10,761          $10,235
                            =======        =======          =======          =======
Change in plan assets
Fair value, beginning of
 period.................    $ 5,184        $ 5,172          $ 5,363          $ 5,439
Actual return on plan
 assets.................       (198)           557             (141)             245
Employer contributions..        --             --               --               252
Benefits paid...........        (49)          (545)             (50)            (278)
Subsidiary spun-off.....        --             --               --              (295)
                            -------        -------          -------          -------
Fair value at end of
 period.................    $ 4,937        $ 5,184          $ 5,172          $ 5,363
                            =======        =======          =======          =======
Reconciliation of funded
 status
Funded status...........    $(7,882)       $(6,212)         $(5,589)         $(4,872)
Unrecognized actuarial
 loss...................      1,504            400              558              --
Unrecognized transition
 obligation.............        --             --               --               --
Unrecognized prior
 service................        --             --               --               --
                            -------        -------          -------          -------
Net amount recognized at
 end of period..........    $(6,378)       $(5,812)         $(5,031)         $(4,872)
                            =======        =======          =======          =======
Amounts recognized in
 balance sheet
Prepaid benefit cost....    $   113        $    --          $    --          $    --
Accrued benefit
 liability..............     (6,491)        (5,812)          (5,031)          (4,872)
                            -------        -------          -------          -------
Net amount..............    $(6,378)       $(5,812)         $(5,031)         $(4,872)
                            =======        =======          =======          =======
</TABLE>

                                     F-14
<PAGE>

                             COLONIAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


(4) Retiree Benefits (Continued)

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

<TABLE>
<CAPTION>
                         Period from
                          November 8    Period from      Four Months
                           through       January 1,         Ended        Eight Months     Year Ended
                         December 31,     through        December 31,        Ended       December 31,
                             2000     November 7, 2000       1999       August 31, 1999      1998
                         ------------ ---------------- ---------------- --------------- ---------------
                                      (Predecessor II) (Predecessor II) (Predecessor I) (Predecessor I)
<S>                      <C>          <C>              <C>              <C>             <C>
Discount rate...........     7.0%           7.5%                7.5%            7.5%          7.0%
Return on plan assets...     8.5%           8.5%                8.5%            8.5%          9.5%
Increase in future
 compensation...........     5.0%           5.0%                4.5%            4.5%          4.0%
Health care inflation
 trend..................     8.0%           8.0%           8.0-10.0%       8.0-10.0%          6.0%
</TABLE>

   The health care inflation rate for 2001 is assumed to be 8%. The rate is
assumed to decrease gradually to 6% in 2005 and remain at that level
thereafter. A one percentage point increase or decrease in the assumed health
care trend rate for 2000 would have the following effects:

<TABLE>
<CAPTION>
                                                   One-Percentage One-Percentage
                                                   Point Increase Point Decrease
                                                   -------------- --------------
                                                          (In Thousands)
<S>                                                <C>            <C>
Service cost and interest cost components.........      $123          $(101)
Post-retirement benefit obligation................      $641          $(610)
</TABLE>

(5) Leases

   The Company leases certain equipment used in its operations. The Company
has capitalized certain of these leases and reflects lease payments as rental
expense in the periods to which they relate.

   Total rental expense for the period from November 8 through December 31,
2000 and the period from January 1 through November 7, 2000 approximated
$128,000 and $688,000, respectively. Total rental expense for the four months
ended December 31, 1999 and eight months ended August 31, 1999 approximated
$265,000 and $545,000, respectively. For the year ended December 31, 1998,
total rental expense approximated $1,150,000.

   The remaining minimum rental commitment for capital leases at December 31,
2000 is as follows:

<TABLE>
<CAPTION>
   Year                                                          (In Thousands)
   ----                                                          --------------
   <S>                                                           <C>
   2001.........................................................     $  642
   2002.........................................................        487
   2003.........................................................        183
   2004.........................................................         41
   2005.........................................................        --
   Later years..................................................        --
                                                                     ------
   Total minimum lease payments.................................     $1,353
   Less--Amount representing interest and executory costs.......        160
                                                                     ------
   Present value of minimum lease payments on capital leases....     $1,193
                                                                     ======
</TABLE>

                                     F-15
<PAGE>

                             COLONIAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


(6) 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.

   The carrying amounts and estimated fair values of the Company's long-term
debt at December 31, 2000 and 1999 are as follows:

<TABLE>
<CAPTION>
                                                   2000              1999
                                             ----------------- -----------------
                                             Carrying   Fair   Carrying   Fair
                                              Amount   Value    Amount   Value
                                             -------- -------- -------- --------
                                                       (In Thousands)
                                                               (Predecessor II)
   <S>                                       <C>      <C>      <C>      <C>
   Long-term debt........................... $121,193 $121,606 $121,667 $116,462
</TABLE>

(7) Related Party Transactions

   The Company paid Eastern $145,000 for the period November 8, 2000 through
December 31, 2000, $725,000 for the period January 1, 2000 through November 7,
2000 and $240,000 in 1999 for legal, tax and corporate services rendered.

   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,
2000, the Company had outstanding borrowings of $47,209,000 and $19,216,000
for working capital and gas inventory, respectively. In 2000, the Company paid
KeySpan Corporate Services $229,000 and $128,000 for interest on these working
capital and gas inventory borrowings, 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.

   In November, 2000, the Company recorded a $250 million advance payable to
KeySpan. A $100 million of this advance was previously owed to Eastern and is
reflected in the Balance Sheet at December 31, 1999. In 2000, the Company
expensed $2,294,000 for interest and debt issuance costs on this advance and
paid Eastern $5,604,000 for interest on its advance. Interest charges equal
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.

(8) Restructuring Charge

   During the third quarter of 2000, the Company recorded a restructuring
charge of $7.0 million related to its decision to exit the gas appliance
repair and service and appliance rental business. The charge includes $5.1
million to write down to fair value the equipment used in the rental business
and $1.2 million for employee severance and termination benefits associated
with the service business. The remaining $0.7 million is associated with the
disposal of inventory and related costs.


                                     F-16
<PAGE>

                             COLONIAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(9) Environmental Matters

   The Company, like many other companies in the natural gas industry, is
party to governmental proceedings requiring investigation and possible
remediation of former manufactured gas plant ("MGP") and related sites. The
Company may have or share responsibility under applicable environmental laws
for the remediation of one former MGP site and related satellite disposal
sites, as well as one non-MGP site and a federal superfund site. The Company
has estimated its potential share of the costs of investigating and
remediating these sites 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 has recorded a liability of approximately $850,000, which represents
its best estimate of the likely cost within a range of reasonable, forseeable
costs. However, there can be no assurance that actual costs will not vary
considerably from this estimate. 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 has received and responded to Requests for Information from the
U.S. Environmental Protection Agency ("EPA") pursuant to Section 104 of the
Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), regarding one federal superfund site that the EPA is currently
investigating. Although the Company cannot determine the amount of its
liability at this time, it does not believe that any such liability will have
a material adverse effect on the Company's financial condition.

   By a rate order issued on May 25, 1990, the Department approved, for
ratemaking purposes, 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
currently believes, in light of the Department rate order, 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 has implemented a severance
program in an effort to reduce its workforce. The Company has recorded a
merger related liability of $1.7 million associated with this severance
program. This severance program is targeted to reduce the Company's workforce
by an additional 20 employees.

                                     F-17
<PAGE>

                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Colonial Gas Company:

   We have audited the accompanying consolidated balance sheet of Colonial Gas
Company (a Massachusetts Corporation and an indirect wholly-owned subsidiary
of KeySpan Corporation) and subsidiary as of December 31, 2000 and 1999, and
the related consolidated statements of earnings, retained earnings and cash
flows for the period from November 8, 2000 through December 31, 2000, the
period from January 1, 2000 through November 7, 2000, the four months ended
December 31, 1999 and the eight months ended August 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 Colonial Gas Company and
subsidiary as of December 31, 2000 and 1999 and the results of their
operations and their cash flows for the period from November 8, 2000 through
December 31, 2000, the period from January 1, 2000 through November 7, 2000,
the four months ended December 31, 1999 and the eight months ended August 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 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 state, 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
January 24, 2001

                                     F-18
<PAGE>

                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Colonial Gas Company:

   We have audited the accompanying consolidated statements of earnings, cash
flows, and retained earnings of Colonial Gas Company and subsidiaries for the
year ended December 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audit.

   We conducted our audit 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 our audit provides a
reasonable basis for our opinion.

   In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated results of operations and
consolidated cash flows of Colonial Gas Company and subsidiaries for the year
ended December 31, 1998, in conformity with accounting principles generally
accepted in the United States.

   Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed in the index to
consolidated financial statements is presented for purposes of complying with
the Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audit 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.

                                          Grant Thornton LLP

Boston, Massachusetts
January 15, 1999

                                     F-19
<PAGE>

                             COLONIAL GAS COMPANY

                         INTERIM FINANCIAL INFORMATION
             For the Two Years Ended December 31, 2000 (Unaudited)

<TABLE>
<CAPTION>
                                         Three Months Ended                   Period from      Period from
                         --------------------------------------------------    October 1        November 8
                             March 31         June 30          Sept. 30      through Nov. 7  through Dec. 31
                         ---------------- ---------------- ---------------- ---------------- ----------------
                         (Predecessor II) (Predecessor II) (Predecessor II) (Predecessor II)
                                                            (In Thousands)
<S>                      <C>              <C>              <C>              <C>              <C>
2000
Operating revenues......     $86,335          $26,718          $ 16,222         $ 8,867          $61,414
Operating margin........     $44,682          $15,055          $  7,240         $ 3,101          $27,308
Utility operating
 earnings (loss)........     $17,924          $ 2,826          $ (5,427)        $(8,249)         $11,376
Net earnings (loss).....     $13,695          $(1,565)         $(10,229)        $(9,261)         $ 6,856
<CAPTION>
                                Three Months Ended                                             Three Months
                         --------------------------------- Two Months Ended One Month Ended       Ended
                             March 31         June 30         August 31         Sept. 30         Dec. 31
                         ---------------- ---------------- ---------------- ---------------- ----------------
                         (Predecessor I)  (Predecessor I)  (Predecessor I)  (Predecessor II) (Predecessor II)
                                                            (In Thousands)
<S>                      <C>              <C>              <C>              <C>              <C>
1999
Operating revenues......     $87,994          $25,580          $  9,052         $ 4,446          $49,652
Operating margin........     $39,451          $13,648          $  4,207         $ 2,161          $25,850
Utility operating
 earnings (loss)........     $16,535          $  (385)         $ (4,871)        $(1,018)         $ 8,880
Net earnings (loss).....     $13,716          $(2,797)         $ (6,399)        $(2,276)         $ 4,989
</TABLE>

   In the opinion of management, the quarterly financial data includes all
adjustments, consisting only of normal recurring accruals, necessary for a
fair presentation of such information.

                                     F-20
<PAGE>

                                                                     SCHEDULE II

                              COLONIAL 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 Of
      Description         Of Period  to Income  Accounts  Reserves      Period
      -----------         ---------- ---------- -------- ----------   ----------
                          For the Period from November 8 through December 31,
                                                  2000
                          ------------------------------------------------------
<S>                       <C>        <C>        <C>      <C>          <C>
Reserve for doubtful ac-
 counts.................    $2,897     $  286    $ --      $  219       $2,964
Reserve self-insurance..    $1,427     $  459    $ --      $  --        $1,886
Reserve for environmen-
 tal expenses...........    $  850     $  --     $ --      $  --        $  850

<CAPTION>
                           For the Period from January 1 through November 7,
                                                  2000
                          ------------------------------------------------------
                                            (Predecessor II)
                          ------------------------------------------------------
<S>                       <C>        <C>        <C>      <C>          <C>
Reserve for doubtful ac-
 count..................    $2,677     $1,695    $ --      $1,475       $2,897
Reserve self-insurance..    $1,108     $  793    $ --      $  474       $1,427
Reserve for environmen-
 tal expenses...........    $  850     $  --     $ --      $  --        $  850

<CAPTION>
                              For the Four Months Ended December 31, 1999
                          ------------------------------------------------------
                                            (Predecessor II)
                          ------------------------------------------------------
<S>                       <C>        <C>        <C>      <C>          <C>
Reserve for doubtful ac-
 counts.................    $3,168     $  344    $ --      $  835       $2,677
Reserve self-insurance..    $1,008     $  100    $ --      $  --        $1,108
Reserve for environmen-
 tal expenses...........    $  200     $  --     $ 650     $  --        $  850

<CAPTION>
                               For the Eight Months Ended August 31, 1999
                          ------------------------------------------------------
                                            (Predecessor I)
                          ------------------------------------------------------
<S>                       <C>        <C>        <C>      <C>          <C>
Reserve for doubtful ac-
 counts.................    $2,551     $1,234    $ --      $  617       $3,168
                                                           $ (760)(*)
Reserve self-insurance..    $1,408     $  559    $ --      $ (199)      $1,008
Reserve for environmen-
 tal expenses...........    $  200     $  --     $--       $  --        $  200
--------
(*) Reserve Balance spun off from Transgas at acquisition.

<CAPTION>
                                  For the Year Ended December 31, 1998
                          ------------------------------------------------------
                                            (Predecessor I)
                          ------------------------------------------------------
<S>                       <C>        <C>        <C>      <C>          <C>
Reserve for doubtful ac-
 counts.................    $3,203     $  654    $ --      $1,306       $2,551
Reserve self-insurance..    $1,593     $  237    $ --      $  422       $1,408
Reserve for environmen-
 tal expenses...........    $  707     $  --     $ --      $  507       $  200
</TABLE>

                                      F-21