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

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                                  FORM 10-K
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|X|   Annual Report  Pursuant to Section 13 or 15(d) of the Securities  Exchange
      Act of 1934 For the fiscal year ended December 31, 1998

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                                      OR
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|_|   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

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                             COLONIAL GAS COMPANY
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            (Exact name of registrant as specified in its charter)
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                        Massachusetts                       04-1558100
                  (State or other jurisdiction of        (I.R.S. Employer
                   incorporation or organization)      Identification Number)

                  40 Market Street, Lowell, Massachusetts        01852
                  (Address of principal executive offices)      (Zip Code)

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Registrant's telephone number, including area code:  (978) 322-3000
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Securities registered pursuant to Section 12(b) of the Act:

                        Common Stock, $3.33 par value
                               (Title of Class)

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

      Indicate by check mark  whether the  registrant  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days.
                        Yes   |X|   No    |_|

      Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's  knowledge,  in definitive proxy or information  statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K |X|

      The aggregate market value of the voting stock held by  non-affiliates  of
the registrant as of January 31, 1999 was $309,761,917.

      The number of shares of the  registrant's  common stock  outstanding as of
January 31, 1999 was 8,914,012.

                     DOCUMENTS INCORPORATED BY REFERENCE

      Portions  of the  registrant's  definitive  proxy  statement  for the 1999
annual meeting of shareholders to be held on April 21, 1999 are  incorporated by
reference into Part III.


<PAGE>



                             COLONIAL GAS COMPANY

        FORM 10-K ANNUAL REPORT FOR THE YEAR ENDING DECEMBER 31, 1998

                              TABLE OF CONTENTS




                                    PART I

Item 1.  Business                                                  3
Item 1A. Executive Officers of the Registrant                     11
Item 2.  Properties                                               12
Item 3.  Legal Proceedings                                        12
Item 4.  Submission of Matters to a Vote of Security Holders      12


                                   PART II

Item 5.  Market for Registrant's Common Stock and Related
         Stockholder Matters                                      13
Item 6.  Selected Financial Data                                  14
Item 7.  Management's Discussion and Analysis of Financial 
         Condition and Results of Operations                      16
Item 8.  Financial Statements and Supplementary Data              23
Item 9.  Changes in and Disagreements with Accountants on 
         Accounting and Financial Disclosure                      44


                                   PART III

Item 10. Directors and Executive Officers of the Registrant       44
Item 11. Executive Compensation                                   44
Item 12. Security Ownership of Certain Beneficial Owners 
         and Management                                           45
Item 13. Certain Relationships and Related Transactions           45


                                   PART IV

Item 14. Exhibits, Financial Statement Schedules, and 
         Reports on Form 8-K                                      45


<PAGE>


                                    PART I

Item 1. Business

                                 THE COMPANY

      Colonial  Gas  Company  ("Colonial"  or the  "Company"),  a  Massachusetts
corporation  formed in 1849,  is primarily a regulated  natural gas utility,  or
local  distribution  company  ("LDC").  The Company serves over 154,500  utility
customers  in 24  municipalities  located  northwest  of Boston and on Cape Cod.
Through its subsidiary,  Transgas Inc.  ("Transgas"),  the Company also provides
over-the-road transportation of liquefied natural gas ("LNG"), propane and other
commodities.  The  Company's  corporate  office is located at 40 Market  Street,
Lowell, Massachusetts 01852. The telephone number is (978) 322-3000.

     On October 17, 1998,  the Company  entered  into an  Agreement  and Plan of
Reorganization (the "Merger Agreement") with Eastern Enterprises ("Eastern"),  a
Massachusetts  business  trust  which owns all of the  outstanding  stock of two
other  Massachusetts  LDCs,  Boston  Gas  Company  ("Boston  Gas") and Essex Gas
Company  ("Essex  Gas").  The Merger  Agreement  provides  for the merger of the
Company with and into a subsidiary of Eastern,  as a result of which the Company
will  become a  wholly-owned  subsidiary  of  Eastern  (the  "Pending  Merger").
Pursuant to the Pending Merger,  the outstanding  shares of the Company's common
stock would  convert into the right to receive cash and Eastern  common stock as
set  forth  in  the  Merger  Agreement.  The  Pending  Merger  was  approved  by
shareholders of Colonial and Eastern at separate  special  shareholder  meetings
which were held on  February  10,  1999.  Completion  of the  Pending  Merger is
subject to receipt of satisfactory  regulatory approvals,  including approval of
the Massachusetts  Department of  Telecommunications  and Energy, the Securities
and Exchange Commission, and antitrust clearance.

      The  Company's  combined  natural gas  distribution  service  areas in the
Merrimack Valley region northwest of Boston and on Cape Cod cover  approximately
622 square miles with a year-round  population of approximately  500,000,  which
increases by approximately 350,000 during the summer tourist season on Cape Cod.
The Company is serving  approximately 51% of potential  customers in its service
areas. Of its 154,500 customers, approximately 90% are residential accounts. The
Company added 4,700 firm sales customers in 1998. The Company's  growth has been
based on new  residential  construction  in its service areas and conversions to
gas from other energy  sources for existing homes and  businesses.  Of the total
number of new customers in 1998, 44% converted from other fuels and 56% were new
construction.

     The Company's 1998  consolidated  operating  revenues were derived 67% from
firm gas sales to residential  customers,  29% from firm gas sales to commercial
and   industrial   customers,   1%  from  non-firm   customers,   2%  from  firm
transportation  customers  and 1% from other  revenues.  For the year 1998,  the
Company had firm gas sales of 17,575 MMcf,  of which 10,347 MMcf was sold in the
Merrimack Valley area and 7,228 MMcf in the Cape Cod area. At December 31, 1998,
91% of the Company's  residential  customers used gas as their source of heating
fuel. The demand for the products and services  furnished by the Company is to a
large extent seasonal, being greatest in the colder months.

<PAGE>


      At December 31, 1998, the Company had 446 full-time-equivalent  employees.
Of those employees, 89 are covered by a collective bargaining agreement with the
United Steelworkers of America which expires in April 2001 and 71 are covered by
a separate  collective  bargaining  agreement  with the United  Steelworkers  of
America  which  expires in  February  2000.  In  addition,  Transgas  employs 53
full-time  employees  of  which  a  total  of 38 are  covered  by  two  separate
collective bargaining agreements with the International Brotherhood of Teamsters
- one for drivers and one for mechanics.  The drivers  agreement expires in June
1999 while the mechanics agreement expires in July 1999.


               GAS SUPPLY, TRANSPORTATION AND STORAGE RESOURCES

      The  Company  and  other  LDCs have  traditionally  been  responsible  for
overseeing  the gas  supplies,  pipeline  transportation  and storage  resources
required to serve their firm sales customers.  As discussed below in "Regulatory
Matters",  pursuant to a February 1999 order by the Massachusetts  Department of
Telecommunications   and  Energy   ("DTE")  on   unbundling   procedures,   each
Massachusetts LDC will retain this  responsibility  for a transition period that
will be up to five years in duration.  Generally, LDCs pay negotiated prices for
pipeline-transported  supplies and tariffed rates approved by the Federal Energy
Regulatory Commission ("FERC") for pipeline transportation and storage.

      As a result of the DTE's recent unbundling orders and directives  outlined
below in "Regulatory  Matters",  the Company  anticipates that the proportion of
gas entering its  distribution  system that is supplied by third party suppliers
will  increase  and that it will be required to  transfer  some of its  upstream
resources to those third party suppliers. The Company does not expect that these
unbundling  changes will have a material financial impact on its business during
the transition period.

      The following table shows the Company's  sources of firm supply  available
to meet its gas requirements  and the actual  components of gas sendout for each
of the last three years:



<PAGE>


                                    1998           1997           1996   
                                MMcf(a)  %     MMcf(a)  %     MMcf(a)  %

Firm Pipeline Transportation 
   Capacity                      30,313       30,313        30,313
                                 ======       ======        ======

Firm Gas Supply Sources
   Contracts for Pipeline-
      Transported  Gas (b)       18,473  73   18,818    75  18,698    71
   LNG contracts                  2,911  12    2,616    10   4,150    15
   Storage inventory at
     January 1 (c)                3,741  15    3,754    15   3,614    14
                                  -----  --    -----    --   -----    --
      Total Available            25,125 100   25,188   100  26,462   100
                                 ====== ===   ======   ===  ======   ===

Gas Sendout
   Pipeline-Transported 
      Supplies (d)               15,100  79   14,763    72  15,115    72
   Supplemental Supplies:
      Underground storage        2,500   13    3,605    17   3,346    16
     LNG-as liquid                 704    4      680     3   1,067     5
     LNG-as vapor                  692    4    1,680     8   1,528     7
     Propane-air                     2    -        5      -      1     -
      Total Sendout             18,998  100   20,733   100  21,057   100
                                ======  ===   ======   ===  ======   ===


Ratio of available firm supply 
   to sendout (e)                     1.32         1.21          1.26

-------------------------
  (a) The  term  "MMcf"  means  one  million  cubic  feet  of  vapor  or  vapor
      equivalent.

  (b) The Company's firm supply purchase  contracts are structured to enable the
      Company to purchase  volumes  equivalent  to the total  amount of its firm
      pipeline  transportation capacity during the winter or peak demand season,
      but less than total firm pipeline  capacity  during the off-peak  season.
      Accordingly,  the total supply  purchase  contract  volumes shown are less
      than total firm transportation capacity for 1998, 1997 and 1996.

  (c) The Company's storage inventory is drawn down and refilled  throughout the
      year depending upon the availability and price of gas sources and upon the
      requirements of the Company's customers. The Company's current underground
      storage capacity is 4,674 MMcf.

  (d) Includes firm and spot volumes.

  (e) The Company's  ratio of available firm supply to sendout was determined by
      dividing total firm gas supply sources by total sendout.

      The Company's  current  portfolio is designed to meet the gas requirements
of its firm sales customers for the foreseeable  future.  Upon completion of the
Pending Merger,  the Company's  portfolio will be integrated into the portfolios
of Boston Gas and Essex Gas in order to enhance efficiencies and reliability for
the natural gas sales  customers of  Eastern's  gas  distribution  subsidiaries.
<PAGE>

Additional   information  concerning  the  Company's  firm  gas  supply  related
resources is set forth below.

Merrimack Valley Service Area Resources

      The Company  maintains  several  contracts with the Tennessee Gas Pipeline
Company  ("Tennessee") for the firm  transportation by interstate  pipeline of a
total  of up to  48,496  Mcf per day of gas  from  gas  production  areas to the
Company's  Merrimack Valley distribution  system. Of this volume,  4,000 Mcf per
day can be delivered  on a firm basis to the  Company's  Cape Cod service  area.
These interstate  pipeline  transportation  contracts with Tennessee have varied
expiration  dates of  between  November  1, 2000 and April 1,  2013.  The supply
purchase  contracts  for the gas to be shipped under these  interstate  pipeline
transportation contracts are also firm, and are generally entered into for terms
of one year or less,  with renewal  options for  additional  one year terms.  In
addition,  the Company  contracts for  underground  storage  service  which,  in
conjunction with other Tennessee firm transportation contracts, provide up to an
additional 23,587 Mcf per day of firm  deliverability in the winter season.  The
underground  storage  contracts  expire  on March  31,  2000 and the  associated
transportation  contracts  expire on  November  1,  2000.  To  supplement  these
capabilities  during the winter season,  the Company's  Merrimack Valley service
area has  on-system  LNG and  propane-air  facilities  which  have an  aggregate
sendout capacity of approximately 76,100 Mcf per day.

Cape Cod Service Area Resources

      The Company  maintains  several  contracts with Algonquin Gas Transmission
Company  ("Algonquin") for the firm  transportation by interstate  pipeline of a
total of up to 45,368 Mcf of gas per day  delivered  to the  Company's  Cape Cod
distribution system. These transportation contracts have varied expiration dates
of between  April 30, 2012 and  October 31,  2013.  The Company  also  maintains
multiple upstream firm transportation contracts from gas production areas to the
Algonquin  pipeline,  as well as upstream  storage service  contracts,  on seven
other  interstate  pipelines.  These upstream  contracts have varied  expiration
dates of between  October 31, 2000 and October 31, 2013.  As with the  Merrimack
Valley system,  the supply  purchase  contracts for gas to be shipped under firm
interstate pipeline transportation contracts to the Cape Cod distribution system
are also firm and are generally entered into for terms of one year or less, with
renewal  options for  additional  one year  terms.  The  Company  also  operates
on-system  facilities  in  the  Cape  Cod  service  area  capable  of  providing
approximately 30,000 Mcf per day of sendout during the winter season.


                              REGULATORY MATTERS

      The Company is a public utility subject to the jurisdiction and regulatory
authority  of the DTE with  respect to its rates as well as to the  issuance  of
securities, franchise territory and other related matters. In July 1997, the DTE
directed  all  investor-owned  LDCs to work  toward  unbundling  their rates and
services in order to make  supplier  choice  available  to all their  customers.
Unbundled rates provide separate charges for (1) gas supply and (2) gas delivery
across the LDC's  distribution  system.  Unbundled  service  involves a customer
<PAGE>

itself  contracting  for gas supply to be brought to the LDC's system,  and then
paying the LDC for the delivery of that supply to its home or business.

      In November,  1998, the Company's  unbundled rates took effect and the DTE
approved  an  agreement  among LDCs  (including  the  Company)  and third  party
suppliers that sets forth standard procedures for serving customers who elect to
buy gas supply from a third party supplier. In February,  1999, the DTE directed
that, for a transition period up to five years in duration: (a) LDCs must retain
the obligation to plan for and procure all upstream pipeline  resources required
to serve their firm sales customers; and (b) any third party supplier seeking to
sell gas supply to an LDC's  customers  must acquire from the LDC, at full cost,
the slice of the LDC's  upstream  resources that the LDC had used to serve those
customers.  The DTE will reevaluate upstream market conditions at the end of the
first three years of the transition period to determine if the directives should
be modified.  As  referenced  above in "Gas Supply,  Transportation  and Storage
Resources",  the Company does not expect that these unbundling changes will have
a material financial impact on its business during the transition period.

      In 1998, the DTE conducted an industry-wide  proceeding on 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 Company has been
using a calculation  method,  approved by the DTE in previous individual Company
filings, based on the useful life of installed conservation measures. As of this
date, the DTE has not yet issued its decision in the  industry-wide  proceeding.
The decision  could result in a  shortening  of the time period for  calculating
lost DSM  margins to less than the full  useful life of  installed  measures.  A
shortening  of the period would result in some  decrease in operating  revenues,
but it is  uncertain  at this time  whether or by how much the  period  would be
shortened and, therefore, what impact it would have on the Company.

      In Massachusetts, LDCs utilize a cost of gas adjustment clause ("CGAC") to
pass  through to firm sales  customers,  via their  monthly gas bill,  the costs
incurred by the  companies in procuring  and  transporting  gas to the companies
distribution  systems.  No mark-up is allowed on those costs, i.e. the LDCs earn
no margin or profit from  selling gas supply  (instead,  margins are earned from
the LDC's distribution or delivery service).

      With the  effectiveness  of unbundled  rates,  Colonial,  as well as other
Massachusetts  LDCs use a Local  Distribution  Adjustment  Clause ("LDAC") which
provides  for the  recovery  of certain  other  costs  from all firm  customers,
regardless of whether they purchase their gas supply from Colonial.  These costs
include:  environmental response costs (see "Environmental Matters" below), FERC
Order 636 transition  costs,  DSM program costs,  DSM related lost margins,  and
certain  unbundling  costs.  These costs were previously  recovered  through the
CGAC.

      In connection  with the Pending  Merger,  the Company has filed a proposed
rate plan with the DTE.  The rate plan  proposes 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. In addition, the rate plan would establish a ten-year
freeze in the Company's base (i.e.  distribution service) rates and would afford
Eastern and Colonial a reasonable  opportunity to recover  merger-related costs.
Prior to this  pending  rate plan  proposal,  the Company had made only two base
rate filings with the DTE since 1984. Its most recent  previous  filing was made
<PAGE>

in 1993 and  resulted in a base rate  increase  designed to generate  additional
revenues of $6.7 million or 3.9 percent annually effective November 1, 1993.

      The Company  follows the  provisions of Statement of Financial  Accounting
Standards No. 71  "Accounting  for the Effects of Certain  Types of  Regulation"
("SFAS 71") requiring the Company to record the financial  statement  effects of
the rate regulation to which the Company is currently subject. Future regulatory
changes could result in the Company no longer  meeting the provisions of SFAS 71
for  all or part of its  business,  thereby  requiring  the  elimination  of the
financial statement effects of regulation for that portion of its business.


                                 COMPETITION

      As discussed  above,  pursuant to recent DTE  directives,  the Company has
unbundled its rates and is in the process of unbundling its services so that all
customers  can have the  opportunity  to choose  their  supplier of natural gas.
Under these  directives,  natural gas  provided to  customers  in the  Company's
franchise areas (whether  supplied by the Company or third party suppliers) will
continue to be delivered to customers through the Company's distribution system.

      Massachusetts  law  protects gas utility  companies  like the Company from
competition  with respect to the  distribution of gas within its franchise areas
by providing that,  where the gas company exists in active  operation,  no other
person may lay pipe in the public ways  without the  approval,  after notice and
hearing, of the municipal  authorities and the DTE. If a municipality desires to
enter the gas  business,  it must take  certain  procedural  steps,  including a
favorable vote by a majority of the voters in a city election or two-thirds vote
at each of two town meetings.  In addition,  the municipality  must purchase the
property of any gas company operating in the municipality (if the company elects
to sell)  to the  extent,  and at such  prices,  as may be  agreed  upon;  if no
agreement is reached, resolution will be determined by the DTE.

      In  addition,   although  FERC  orders  have  generally  permitted  larger
industrial  users to obtain piped gas from other sources and by-pass a utility's
distribution  system,  the Company  has not seen nor does it believe  that these
FERC orders will have a material adverse effect on its business, in part because
large industrial users are not a significant part of its customer base.

      Fuel oil  suppliers,  electric  utilities  and propane  suppliers  provide
competition  generally for  residential,  commercial and  industrial  customers.
Interruptible  gas service is generally in competition with No. 6 fuel oil which
most of the interruptible customers are equipped to use. Lower prices of oil and
other  fuels may  adversely  affect the  Company's  ability to retain or attract
customers.  The Company's rates for bundled gas service have remained  generally
competitive  with the price of alternative  fuels,  but the long-term  impact of
changes in fuel prices and changes in state  regulatory  policies on the Company
and its rates cannot be predicted.



<PAGE>


                            ENVIRONMENTAL MATTERS



      The Company is subject to Federal and state laws and  regulations  dealing
with  environmental  protection.  Compliance  with such  environmental  laws and
regulations  has  resulted  in  increased  costs with  respect to the  Company's
existing operations.

      Working with the Massachusetts Department of Environmental Protection, the
Company is engaged in site  assessments  and evaluation of remedial  options for
contamination that has been attributed to the Company's former gas manufacturing
site and at various  related  disposal  sites.  During 1990,  the DTE ruled that
Colonial and eight other  Massachusetts  gas distribution  companies can recover
environmental response costs related to former gas manufacturing operations over
a seven-year period,  without carrying costs, through the CGAC. Through December
31, 1998, the Company had incurred  environmental  response costs of $12,582,000
of which $8,949,000 has been recovered from customers to date.

      As of December 31, 1998,  the Company has recorded on the balance  sheet a
long-term  liability of $200,000 and, based upon anticipated rate recovery,  has
recorded a corresponding  regulatory  asset.  This amount  represents  estimated
future response costs for these sites based on the Company's  preferred  methods
of remediation.  Actual  environmental  response costs to be incurred depends on
various factors, and therefore future costs may differ from the amount currently
recorded as a liability.




<PAGE>


                                TRANSGAS INC.

      Transgas  primarily  provides  over-the-road  transportation  of liquefied
natural gas ("LNG"),  propane and other commodities.  In 1998, Transgas provided
such service to approximately 24 commercial and gas utility customers located in
the  eastern  half  of the  United  States.  Transgas  also  provides  a  highly
specialized  LNG portable  pipeline  service,  which  permits gas  utilities and
pipeline  companies to provide a continuous supply of natural gas to communities
when pipeline gas is  interrupted  for scheduled or emergency  shutdowns or when
supplemental  supplies  are  required  during  periods  of peak  winter  demand.
Transgas is subject to various federal and state regulations applicable to motor
carriers of hazardous materials.

      Transgas  had  revenues  of  $3,723,000  in  1998.  Approximately  61%  of
Transgas'  revenue in 1998 was derived from  transporting  LNG from Distrigas of
Massachusetts Corporation's import terminal, located in Everett,  Massachusetts.
Transgas' revenues decreased $1,806,000,  or 33%, compared to 1997 due primarily
to a decrease in the demand for transportation of LNG which occurred for most of
the year.  The decrease was primarily  due to the warmer than normal  weather in
the winter of 1997-98.

      Transgas  provides  over-the-road  transportation  services by utilizing a
fleet of 40 tractors.  Transgas owns 60 trailers which are specifically designed
for the transportation of LNG and other cryogenic liquids.  Transgas also leases
16 LNG trailers.  In addition,  Transgas owns 5 trailers  which are designed for
the  transportation  of propane.  Transgas  also leases 6 propane  trailers.  In
addition to the  equipment  described  above,  Transgas also has 14 portable LNG
vaporizer trailers, as well as 2 flat bed trailers and 2 van trailers.

      Transgas competes with other motor carriers engaged in the  transportation
of various gases and other products.  Transgas believes, however, that it is the
leading over-the-road  transporter of LNG due to the size of its specialized LNG
trailer fleet and the number of LNG loads it delivers annually.



<PAGE>


Item 1A. Executive Officers of the Registrant.

      The  following  table  indicates  the  present  executive  officers of the
Company,  their ages,  the dates when their  service with the Company  began and
their respective positions with the Company.

                                                           Affiliated with
    Name and Age              Position with Company        Company Since

Frederic L. Putnam,           Chairman and Senior 
  Jr. (74)                      Executive Officer               1953
Frederic L. Putnam,           President and Chief Executive 
   III (53)                     Officer                         1975
Charles W. Sawyer (53)        Executive Vice President and
                                Chief Operating Officer         1976
Nickolas Stavropoulos (41)    Executive Vice President
                                - Finance, Marketing, and   
                                Chief Financial Officer         1979
John P. Harrington (56)       Senior Vice President - Gas 
                                Supply and Assistant to the 
                                President                       1966
Victor W. Baur (55)           President - Transgas Inc.         1972
Dennis W. Carroll (52)        Vice President and Treasurer      1990


      Mr. Putnam,  Jr. has been Chairman of the Board of Directors  since 1981
and the Senior  Executive  Officer  since  February  1995 and before  that the
Chief Executive Officer since 1977. He has also been a Director since 1973.

      Mr.  Putnam,  III, the son of F. L. Putnam,  Jr., has been  President  and
Chief  Executive  Officer since February  1995. He had been President  since May
1994,  Executive  Vice  President and General  Manager from April 1993 until May
1994 and before that Vice  President and General  Manager from August 1989 until
April 1993. He has also been a Director since November 1991.

      Mr.  Sawyer  has been  Executive  Vice  President  and  Chief  Operating
Officer since  February  1995. He had been Vice  President - Operations  since
August 1989.

      Mr. Stavropoulos has been Executive Vice President - Finance,  Marketing
and Chief Financial  Officer since February 1995. He had been Vice President -
Finance and Chief  Financial  Officer  since August  1989.  He has also been a
Director since February 1993.

      Mr.  Harrington  has  been  Senior  Vice  President  -  Gas  Supply  and
Assistant to the President  since  February 1995. He had been Vice President -
Gas Supply since August 1989. He has also been a Director since February 1993.

      Mr. Baur has been  President of Transgas  Inc.  since July 1990.  He has
been a Director of the Company since August 1993.

      Mr. Carroll has been Vice President and Treasurer since August 1990.

      These  officers hold office until the next annual  meeting of the Board of
Directors or until their  successors are duly elected and qualified,  subject to
earlier removal.



<PAGE>


Item 2. Properties.

      The Company has two  principal  operations  centers and two  principal LNG
storage  facilities.  One of these  storage  facilities is located in Tewksbury,
Massachusetts  and has a capacity of approximately  1,000,000 Mcf of LNG and the
other  is  located  in  South  Yarmouth,  Massachusetts  and has a  capacity  of
approximately  175,000 Mcf of LNG. In general,  the Company's gas production and
storage facilities, metering and regulation stations and operations centers, are
located  on  land  it  owns.  In  addition,   the  Company  owns  its  corporate
headquarters, a 36,000 square foot office facility in Lowell, Massachusetts.

      The Company's  distribution mains of approximately 3,129 miles are located
within  public  highways  under  franchises  or permits  from state or municipal
authorities,  or on land owned by others under  easements  or licenses  from the
owners.  The  Company's  first  mortgage  bonds are  collateralized  by  utility
property.

      Management  believes  that the Company's  properties  are adequate for the
conduct of its business for the reasonably foreseeable future.

Item 3. Legal Proceedings.

      See Item 1, "Business--Environmental Matters" above, which is incorporated
herein.

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

      A Special  Meeting of Shareholders of the Company was held on February 10,
1999. At that Special Meeting,  the shareholders  voted to approve the Agreement
and Plan of  Reorganization  dated as of October 17, 1998  between  Colonial Gas
Company and Eastern  Enterprises,  with 6,727,284  shares voting for and 217,193
shares voting against or withholding authority.



<PAGE>


                                   PART II

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

      Colonial  Gas  Company's  Common  Stock is  traded  on the New York  Stock
Exchange under the ticker symbol CLG. Prior to September 18, 1997, the Company's
Common Stock was traded on the Nasdaq Stock Market.  At December 31, 1998, there
were approximately 15,000 shareholders of the Company's Common Stock,  including
4,721 shareholders of record.

Market Prices and Dividends

The  following  table  reflects the high and low sales prices as reported by the
New York  Stock  Exchange  (since the third  quarter  of 1997) and Nasdaq  Stock
Market,  for shares of the  Company's  Common  Stock for 1998 and 1997,  and the
quarterly dividends paid per share.

                                      Sales Prices       Dividends
                                    High       Low    Paid per Share

1998

The Year                         $35.438    $26.500      $1.370
4th  Quarter                      35.438     28.000        .345
3rd  Quarter                      30.000     27.125        .345
2nd  Quarter                      29.250     26.500        .345
1st  Quarter                      29.500     26.500        .335

1997                                                           

The Year                         $30.063    $19.250      $1.330
4th  Quarter                      30.063     23.688        .335
3rd  Quarter                      25.250     20.500        .335
2nd  Quarter                      22.750     19.250        .335
1st  Quarter                      24.000     20.000        .325



<PAGE>



Item 6. Selected Financial Data.

<TABLE>
<CAPTION>

FINANCIAL AND OPERATING STATISTICS
(For the Years Ending December 31)        1998          1997          1996          1995          1994 
Operating Revenues (In Thousands)

<S>                                   <C>           <C>           <C>           <C>           <C>     
Residential - Sales ..............    $113,008      $121,649      $108,879      $103,991      $104,812
Commercial and industrial - Sales       48,112        59,163        54,324        52,926        56,358
Firm transportation ..............       2,643         1,941         1,843         1,294         1,210
Non-firm sales ...................       1,809         2,530         2,985         3,745         2,429
Non-firm transportation ..........         632           631           453           424           401
Other ............................       1,774         1,226         1,394         1,288           117
                                         -----         -----         -----         -----           ---
     Total operating revenues ....    $167,978      $187,140      $169,878      $163,668      $165,327
                                      ========      ========      ========      ========      ========
Gas Sold (MMcf)
Residential ......................      11,390        12,492        12,094        11,361        11,190
Commercial and industrial ........       6,185         7,505         7,469         7,199         7,526
Non-firm .........................           7            62           648         1,148           729
                                             -            --           ---         -----           ---
     Total gas sales .............      17,582        20,059        20,211        19,708        19,445
Gas Transported (MMcf)
Firm .............................       4,797         3,278         3,918         2,537         6,090
Non-firm .........................       2,646         3,791         2,671         3,224         4,185
                                         -----         -----         -----         -----         -----
     Total gas transported .......       7,443         7,069         6,589         5,761        10,275
                                         -----         -----         -----         -----        ------
     Total gas sold and transported     25,025        27,128        26,800        25,469        29,720
                                        ======        ======        ======        ======        ======
Gas Purchased (MMcf)
Pipeline .........................      15,100        14,763        15,115        14,659        14,392
Underground storage ..............       2,500         3,605         3,346         3,270         3,112
LNG - as liquid ..................         704           680         1,067           844         1,129
LNG - as vapor ...................         692         1,680         1,528         1,574         1,236
Propane ..........................           2             5             1             8            25
                                             -             -             -             -            --
     Total gas purchased .........      18,998        20,733        21,057        20,355        19,894
Company use and other ............      (1,416)         (674)         (846)         (647)         (449)
                                          ----          ----          ----          ----          ---- 
     Available for sale .........       17,582        20,059        20,211        19,708        19,445
                                        ======        ======        ======        ======        ======
                                        
Customers - End of period (a)
Residential ......................     139,575       135,655       130,161       126,323       122,024
Commercial and industrial ........      14,725        14,100        13,565        13,387        13,018
Firm transportation ..............         175            30            19            11             8
Non-firm sales ...................          10            22            25            27            21
Non-firm transportation ..........          15            15             5             2             2
                                            --            --             -             -             -
     Total customers - end of ....     154,500       149,822       143,775       139,750       135,073
                                       =======       =======       =======       =======       =======
period
Average Annual Mcf Sold/Customer
Residential ......................          83            94            94            91            96
Commercial and industrial ........         429           543           554           545           584
Average Annual Bill/Customer
Residential ......................   $     821     $     915     $     849     $     837     $     900
Commercial and industrial ........   $   3,338     $   4,277     $   4,031     $   4,009     $   4,375
Average Revenue/Mcf
Residential ......................   $    9.89     $    9.73     $    9.03     $    9.20     $    9.37
Commercial and industrial ........   $    7.78     $    7.88     $    7.27     $    7.35     $    7.49
Residential Heating Customers as a
     % of all Residential Customers         91%           91%           90%           90%           90%
Highest Daily Sendout (Mcf) ......     169,088       183,063       170,984       199,275       204,896
Percent Colder (Warmer) than
20-year average ..................       (11.8)%         1.1%          3.0%         2.4%          5.0%

</TABLE>

-----------------------------------------------------------------------------
(a)Customer  count  data has been  updated  for the years  1994-1997  due to the
implementation in 1998 of a new customer billing system, and its improved 
customer count methodology.


<PAGE>


SELECTED FINANCIAL DATA

(For the Years Ending December 31)
(In Thousands Except Per Share Amounts)  
                                   1998     1997     1996     1995     1994
Balance Sheet Data:
Assets:
Utility property - net         $292,213 $274,532 $250,983 $235,555  $221,685
Non-utility property - net        7,129    7,312    5,925    5,036     3,479
Capital leases - net              1,583    2,630    1,811    2,253     2,948
Current assets                   67,568   67,967   67,558   61,002    65,568
Deferred charges and other 
     assets                      32,511   36,550   38,135   38,575    37,668
                                 ------   ------   ------   ------    ------
      Total                    $401,004 $388,991 $364,412 $342,421  $331,348
                               ======== ======== ======== ========  ========
Capitalization and Liabilities:
Capitalization:
Common equity                  $128,922 $122,132 $113,906 $105,070  $ 99,175
Long-term debt                  120,000  100,102   95,266   75,418    77,923
                                -------  -------   ------   ------    ------
      Total Capitalization      248,922  222,234  209,172  180,488   177,098
Capital lease obligations           963    1,617      930    1,359     2,237
Current liabilities              89,583  102,508   94,169  101,666    91,382
Deferred credits and reserves    61,536   62,632   60,141   58,908    60,631
                                 ------   ------   ------   ------    ------
      Total                    $401,004 $388,991 $364,412 $342,421  $331,348
                               ======== ======== ======== ========  ========

Income Statement Data:
Operating revenues             $167,978 $187,140 $169,878 $163,668  $165,327
Cost of gas sold                (88,127)(102,455) (87,188) (83,631)  (87,458)
                                ------- --------  -------  -------   ------- 
Operating margin                 79,851   84,685   82,690   80,037    77,869
Operating expenses (including 
     income taxes)              (58,993) (61,829) (60,536) (58,512)  (60,331)
                                -------  -------  -------  -------   ------- 
Utility operating income         20,858   22,856   22,154   21,525    17,538
Other income - net of 
     income taxes                 1,290    1,218    3,033    1,509     1,880
Merger-related expenses - net 
     of income taxes             (1,126)       -        -        -         -
Interest and debt expense        (8,734)  (8,034)  (8,709)  (9,270)   (8,409)
                                 ------   ------   ------   ------    ------ 
Net income                     $ 12,288  $16,040  $16,478  $13,764   $11,009
                               ========  =======  =======  =======   =======

Capitalization Ratios:
Common equity                       52%      55%      54%      58%      56%
Long-term debt                      48%      45%      46%      42%      44%

Common Stock Data:
Average shares outstanding        8,781    8,598    8,432    8,294     8,119
Basic earnings per share          $1.40    $1.87    $1.95    $1.66     $1.36 (a)
Dividends paid per share:         $1.37    $1.33    $1.295   $1.275   $1.255
Dividend payout rate                 98%      71%      66%      77%      92%
Book value per share             $14.48   $14.06   $13.37   $12.56    $12.05
Dividends as a percent of 
     book value                       9%       9%      10%      10%      10%
Market price per share            $34.88   $28.81   $21.25   $20.25   $19.25
Market price as a percent 
     of book value                   241%     205%     159%     161%     160%
Return on average common equity      9.8%    13.6%    15.1%    13.5%    11.4%
(a) 1994 is after a restructuring charge of $.24 per share.



<PAGE>


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

RESULTS OF OPERATIONS

Net Income and Dividends
Net income and basic earnings per share were  $12,288,000  ($1.40),  $16,040,000
($1.87),  and $16,478,000  ($1.95) for the years ended December 31, 1998,  1997,
and 1996, respectively.
   Net income was  unfavorably  impacted by  significantly  warmer than  20-year
average  temperatures  in 1998,  and  favorably  impacted by colder than 20-year
average temperatures in 1997 and 1996. This is summarized as follows:

                                                   1998     1997     1996
                                                   ----     ----     ----
Percent colder (warmer) than 20-year average       (11.8%)  1.1%     3.0%

Percent colder (warmer) than prior year            (12.8%)  (1.8%)   0.6%

Other items  which had an impact on net income are  discussed  below.  
     Dividends paid per common share were $1.37 in 1998, $1.33 in 1997 and
$1.295 in 1996. The Company has paid dividends for 62 consecutive years, and has
increased dividends each year for the past 19 years.


Operating Revenues
Operating  revenues  were  $167,978,000  in  1998,   $187,140,000  in  1997  and
$169,878,000 in 1996. Operating revenues are impacted by the volumes of gas sold
and  transported,  changes  in  base  rates  as  approved  by the  Massachusetts
Department of  Telecommunications  & Energy ("DTE"), and changes in gas costs to
customers via a cost of gas adjustment clause ("CGAC").
   The  volumes of gas sold and  transported  are  affected by  fluctuations  in
weather and the number of customers  being served.  Firm customers  increased by
14,500  over the last three years from  140,000 in  December  1995 to 154,500 in
December 1998, an increase of 10.4%. The chart below  summarizes  volumes of gas
sold and transported and number of firm customers:

                                                   1998     1997     1996
                                                   ----     ----     ----
(In MMcf)
Gas sold
    Firm                                         17,575    19,997   19,563
    Non-Firm                                          7        62      648
Gas transported
    Firm                                          4,797     3,278    3,918
    Non-Firm                                      2,646     3,791    2,671
                                                  -----     -----    -----
           Total gas sold and transported 
           (In MMcf)                             25,025    27,128   26,800
                                                 ======    ======   ======

Firm Customers                                  154,500   150,000  144,000
                                                =======   =======  =======

   Operating revenues decreased  $19,162,000,  or 10.2%, from 1997 to 1998. This
decrease  resulted  from  weather  which was 11.8%  warmer than normal and 12.8%
warmer than last year, and lower gas costs,  partially offset by customer growth
of 3.1%.
<PAGE>

   Operating revenues increased  $17,262,000,  or 10.2%, from 1996 to 1997. This
increase  resulted  from customer  growth of 4.2% and higher gas costs,  despite
weather which was 1.8% warmer than the prior year.

Cost of Gas Sold
Average  cost of gas sold per Mcf was $4.98 in 1998,  $5.08 in 1997 and $4.29 in
1996.  Cost of gas sold is impacted by changes in sales  volumes,  the price and
mix of gas purchased and used to satisfy demand, and profits from non-firm sales
and transportation (substantially all of which flow back to firm sales customers
as a credit through the CGAC).

Operating Expenses
Operations  expense was $27,793,000 in 1998, a decrease of $2,251,000,  or 7.5%,
from 1997, and $30,044,000 in 1997, a decrease of $328,000,  or 1.1%, from 1996.
The  significant  decrease in operations  expense in 1998 was due primarily to a
one-time  decrease in the reserve for  uncollectable  accounts of  approximately
$1,137,000  -- a direct  result  of the  unbundling  of the  Company's  rates on
November 1, 1998. As of that date, the gas supply or commodity  component of bad
debt  expense is being  recovered  through  the cost of gas  adjustment  clause,
thereby  decreasing the Company's bad debt expense by  approximately  50%. Other
factors which impacted the decrease in operations expense in 1998 were lower bad
debt expense in general, lower pension costs and lower insurance expenses.
   Maintenance  expense  increased  $291,000,  or 6.5%,  in 1998  from  1997 and
increased  $27,000,  or  0.6%,  in 1997  from  1996.  The  increase  in 1998 was
primarily due to increased labor costs.
   Depreciation and amortization  expense increased $1,386,000 or 11.5%, in 1998
and  $821,000  or 7.3% in 1997.  The  increase in 1998 was due to an increase in
utility  property  and the  completion  of  significant  software  systems.  The
increase in 1997 was due to an increase in utility property.
   Local property and other taxes decreased 2.0% in 1998 from 1997 and decreased
2.1% in 1997 from  1996.  The  decreases  in 1998 and 1997  were due to  reduced
property taxes, based on lower tax rates and abatements.

Income Taxes
Total Federal income and state franchise taxes decreased  $2,156,000,  or 21.6%,
in 1998 from 1997 due to a lower level of income from  utility  operations,  and
increased $884,000,  or 9.7%, in 1997 from 1996 as a result of a higher level of
income for the utility operations.

Other Operating Income (Expense)
Other  operating  income  (expense)  net of income  taxes was  $393,000 in 1998,
$645,000  in 1997 and  $2,276,000  in 1996.  Other  operating  income  primarily
includes the results of the Company's  wholly-owned  energy trucking  subsidiary
(Transgas Inc.). Also included are heating and water heating equipment sales and
installations.
   Transgas' 1998  financial  results were driven by a 37% decrease in liquefied
natural gas ("LNG")  hauls leading to a $1,806,000  decrease in energy  trucking
revenue and a $294,000 decrease in energy trucking net income.  This decrease in
demand of  transportation of LNG occurred for most of the year and was primarily
due to the warmer than normal weather in the winter of 1997-98.
<PAGE>

   Transgas' 1997  financial  results were driven by a 50% decrease in LNG hauls
leading to a  $5,502,000  decrease in energy  trucking  revenue and a $1,699,000
decrease  in  energy   trucking   net  income.   This   decrease  in  demand  of
transportation of LNG occurred for most of the year and was primarily due to the
warmer than normal weather in the first quarter of 1997.
   Factors  potentially  affecting the future financial results of Transgas,  in
addition to the impact of weather variations,  include the amount of LNG used by
local distribution  companies  throughout the northeast United States to satisfy
requirements of their customers;  the price of domestic and Canadian natural gas
compared to imported  LNG; the continued  availability  of imported LNG; and the
level of  construction  and major  maintenance  projects of interstate  pipeline
companies which drives the demand for portable pipeline services.

Non-Operating Income, Net
Non-operating  income,  net of income taxes,  was $897,000 in 1998,  $573,000 in
1997 and $757,000 in 1996.  Non-operating  income  includes  allowance for funds
used during construction, interest income and miscellaneous other income.

Merger Related Expenses, Net
The Company  recorded  $1,126,000 of after-tax  merger related expenses in 1998.
These costs are  associated  with the  Company's  pending  merger  with  Eastern
Enterprises.

Interest and Debt Expense
Interest and debt expense  increased  $700,000,  or 8.7% in 1998 from 1997.  The
increase in 1998 was due to increased  short-term  borrowing balances.  Interest
and debt expense decreased $675,000, or 7.7%, in 1997. This was due to decreased
levels of  short-term  debt and greater  interest  income on higher  balances of
regulatory assets, which offset interest expense. These were partially offset by
an increase in interest on long-term debt.


Effects of Inflation
Inflation generally has a negative impact upon the Company's profitability since
the rates charged to the Company's utility  customers,  excluding changes in the
cost of gas sold, cannot be increased without formal proceedings before the DTE.
Changes in the cost of gas sold are  automatically  reflected in customer  rates
pursuant to semi-annual adjustments under the CGAC. In the absence of authorized
rate increases, the Company must look to increased productivity and higher sales
volumes to offset inflationary  increases in its other costs of operations.  The
present regulatory process permits the Company to earn a rate of return based on
the  historical  cost of utility  property  without  recognition  of the current
replacement  cost. The Company's policy is to file for an increase in rates only
when  increases in  productivity  and customers are not sufficient to counteract
the impact of inflation.



<PAGE>


Regulatory Matters
For the impact of regulatory matters on the Company's  operations,  please refer
to the  "Regulatory  Matters"  section of Item 1 of this  report,  which is also
incorporated by reference herein.

Environmental Matters
For the impact of  environmental  matters on the  Company's  operations,  please
refer to the "Environmental  Matters" section of Item 1 of this report, which is
also incorporated by reference herein.


LIQUIDITY AND CAPITAL RESOURCES

Operating Activities
The  Company's  liquidity  is affected  by its  ability to  generate  funds from
operations and to access capital markets.  The Company's operations are seasonal
with its cash flow reflecting this seasonality.  The Company typically generates
approximately  70 to 80  percent  of its annual  operating  revenues  during the
November  through  April heating  season,  which results in a high level of cash
flow from operations from late winter through early summer.  As a result of this
seasonality,  the Company's liquidity can be affected by significant  variations
in weather.  Short-term  borrowings are highest during the fall and early winter
months due to the  completion  of the annual  construction  program and seasonal
working capital requirements.

Investing Activities
The Company invests in property,  plant and equipment to improve and protect its
distribution  system, and to expand its system to meet customer demand.  Utility
capital  expenditures  were  $31,093,000  in  1998,  $35,788,000  in  1997,  and
$26,875,000  in 1996.  The Company's  long-range  plan calls for annual  utility
expenditures averaging $27,000,000 over the next five years of which over 56% is
budgeted for new business.



(In Thousands)                 1999      2000       2001       2002       2003
-------------------------------------------------------------------------------
Distribution                 $23,100    $23,800    $24,700    $25,600    $26,500
Production                       100        400        300        900        100
Information Systems            3,100      2,400        500        400        300
Automated Meter Reading          300        300        300        200        300
General                          300        300        300        300        300
                                 ---        ---        ---        ---        ---
   Total Capital             $26,900    $27,200    $26,100    $27,400    $27,500
                             =======    =======    =======    =======    =======
Expenditures




<PAGE>


Financing Activities
   The  Company  has raised  permanent  capital  during the last three  years as
follows:

(In Thousands)                               1998      1997         1996
                                             ----      ----         ----
Common Stock Under Dividend Reinvestment
   and Common Stock Purchase Plan and
   Employee Savings Plan                    $6,541      $3,621      $3,277
   Medium term notes under the first
        mortgage indenture                 $40,000     $15,000     $30,000

   Long-Term Debt instruments  maturing during the years 1999 through 2003 total
$102,000 in 1999, $0 in 2000,  2001 and 2002 and  $10,000,000 in 2003. Long-term
debt  with a  principal  amount  of  $15 million,  which is due in 2027,  can be
redeemed by the holder in 2002.
   The Company has a $75 million  credit  facility  expiring in September  2000,
which allows it to meet its seasonal working capital needs. Up to $30 million of
the credit facility can be used by the Company's gas inventory trust. The credit
facility  allows  the  Company  the  option  to  borrow  under  any one of three
alternative rates.
   The equity and debt components of the Company's capital structure at year-end
is shown in the table below:
                                                 1998     1997    1996
                                                 ----     ----    ----
Equity                                            52%      55%    54%
Long-Term Debt                                    48%      45%    46%

   As of April 1998, the quarterly  dividend paid on the Company's  Common Stock
was  increased to $.345 per share or an  annualized  dividend  rate of $1.38 per
share.


YEAR 2000

State of Readiness
     The Company's  merger with Eastern  Enterprises is expected to be completed
by  mid-year  1999 and in  connection  with that  pending  merger,  the  Company
anticipates   addressing   certain  Year  2000  ("Y2K")  issues  through  system
integrations with Boston Gas Company,  Eastern's largest gas utility subsidiary.
The Company has  established,  in concert  with  Boston Gas, a  specialized  Y2K
program team that is implementing a systematic program of inventory,  assessment
and remediation. Information technology ("IT") systems and embedded chip systems
which are "mission critical",  i.e. those which would have a significant adverse
impact on the operation of the core business of the Company and its  subsidiary,
Transgas, in the event of a Y2K problem, have been identified. It is anticipated
that any necessary  testing,  upgrading,  replacement  or other  remediation  of
mission  critical IT systems will be completed by the end of the second  quarter
of 1999.  Other "less than critical" IT systems are also scheduled to be checked
and tested and/or  upgraded,  as required,  by the end of the second  quarter of
1999.


<PAGE>


   With  respect to  embedded  chip  systems,  the  Company  has  completed  its
inventory and is finalizing its assessment and action plan. Testing,  upgrading,
replacement or other  remediation  of embedded  chips is being  scheduled and is
anticipated to be completed by the end of the third quarter of 1999.
   The Company has identified  critical third party vendor  relationships and is
working on determining  the Y2K readiness of such vendors.  This critical vendor
component of the Company's Y2K program is scheduled for completion by the end of
the second  quarter of 1999.  Notwithstanding  the Company's  efforts with third
parties,  there can be no assurance  that the systems of third  parties on which
the Company's  systems rely will be timely converted or that any such failure to
convert  by a third  party  would not have an  adverse  effect on the  Company's
operations.


Cost of Year 2000 Remediation
   Based on its current information, without any system integrations with Boston
Gas, the Company believes the cost of its Y2K compliance would  approximate $1.5
million.  With the system  integrations  expected  with Boston Gas,  the Company
anticipates  actual Y2K remediation  costs to be  significantly  lower than this
amount.  Substantially  all Y2K remediation costs are expected to be incurred in
1999.

Risks of Year 2000 Issues and Contingency Plans
   Given its efforts to minimize the risk of Y2K failure by its internal systems
and its  distribution  network control  systems,  the Company believes its worst
case   scenario   would   involve   failures  by  a  pipeline   supplier  or  by
telecommunications,  electricity or banking services.  A short term interruption
in pipeline supplies would require the utilization of  locally-stored  liquefied
natural gas supplies. A telecommunications  or electric outage would require the
Company to enact business  contingency and disaster  recovery measures to enable
the continuation of service to its customers.
   The Company has  initiated the  development  of a business  contingency  plan
concerning Y2K risks to its internal  systems,  embedded  chips and  significant
suppliers. Business processes are expected to be assessed and prioritized by the
end of the first quarter of 1999. Detailed plans for critical business processes
are expected to be developed and tested by the end of the third quarter of 1999.

PENDING MERGER WITH EASTERN ENTERPRISES

     On October 17, 1998,  the Company  entered  into an  Agreement  and Plan of
Reorganization (the "Merger Agreement") with Eastern Enterprises ("Eastern"),  a
Massachusetts  business  trust  which owns all of the  outstanding  stock of two
other  Massachusetts  LDC's,  Boston Gas  Company  ("Boston  Gas") and Essex Gas
Company  ("Essex  Gas").  The Merger  Agreement  provides  for the merger of the
Company with and into a subsidiary of Eastern,  as a result of which the Company
will  become a  wholly-owned  subsidiary  of  Eastern  (the  "Pending  Merger").
Pursuant to the Pending Merger,  the outstanding  shares of the Company's common
stock would  convert into the right to receive cash and Eastern  common stock as
set  forth  in  the  Merger  Agreement.  The  Pending  Merger  was  approved  by
shareholders of Colonial and Eastern at separate  special  shareholder  meetings
which were held on  February  10,  1999.  Completion  of the  Pending  Merger is
subject to receipt of satisfactory  regulatory approvals,  including approval of
the Massachusetts
<PAGE>

Department  of  Telecommunications  and  Energy,  the  Securities  and  Exchange
Commission, and antitrust clearance.


FORWARD LOOKING INFORMATION

This report and other Company reports contain forward looking  statements  which
are subject to the  inherent  uncertainties  in  predicting  future  results and
conditions. Certain factors that could cause actual results to differ materially
from those projected in these forward looking  statements  include,  but are not
limited  to,  variations  in  weather,  changes in the  regulatory  environment,
customers' preferences on energy sources, general economic conditions, increased
competition and other uncertainties,  all of which are difficult to predict, and
many of which are beyond the control of the Company.




<PAGE>


Item 8. Financial Statements and Supplementary Data.

                        Index to Financial Statements

Consolidated Statements of Income....................................25

Consolidated Balance Sheets..........................................26

Consolidated Statements of Cash Flows................................28

Consolidated Statements of Common Equity.............................29

Notes to Consolidated Financial Statements...........................30

Report of Independent Certified Public Accountants...................42

Report of Management.................................................43
<PAGE>

                      [This page intentionally left blank]


<PAGE>


                             COLONIAL GAS COMPANY
                      CONSOLIDATED STATEMENTS OF INCOME

                                                 Year Ended December 31,
(In Thousands Except Per Share Amounts)          1998        1997         1996 
                                                 ----        ----         ---  

Operating Revenues .........................   $167,978    $187,140    $169,878
Cost of gas sold ...........................     88,127     102,455      87,188
                                                 ------     -------      ------
   Operating Margin ........................     79,851      84,685      82,690
                                                 ------      ------      ------
Operating Expenses:
   Operations ..............................     27,793      30,044      30,372
   Maintenance .............................      4,794       4,503       4,476
   Depreciation and amortization ...........     13,435      12,049      11,228
   Local property taxes ....................      3,074       3,139       3,189
   Other taxes .............................      2,081       2,122       2,183
                                                  -----       -----       -----
     Total Operating Expenses ..............     51,177      51,857      51,448
                                                 ------      ------      ------
Income Taxes:
   Federal income tax ......................      6,482       8,264       7,001
   State franchise tax .....................      1,334       1,708       2,087
                                                  -----       -----       -----
     Total Income Taxes ....................      7,816       9,972       9,088
                                                  -----       -----       -----
Utility Operating Income ...................     20,858      22,856      22,154
                                                 ------      ------      ------
Other Operating Income (Expense):
   Energy Trucking revenues ................      3,723       5,529      11,031
   Energy Trucking expenses, including
     income taxes and interest .............     (3,690)     (5,202)     (9,005)
                                                 ------      ------      ------ 
     Energy Trucking Net Income ............         33         327       2,026
   Other, net of income taxes ..............        360         318         250
                                                    ---         ---         ---
     Total Other Operating Income ..........        393         645       2,276
                                                    ---         ---       -----
Non-Operating Income, Net of Income Taxes ..        897         573         757
                                                    ---         ---         ---
Merger Related Expenses, Net of Income Taxes     (1,126)         --          --
                                                 ------                        
Income Before Interest and Debt Expense ....     21,022      24,074      25,187
                                                 ------      ------      ------
Interest and Debt Expense ..................      8,734       8,034       8,709
                                                  -----       -----       -----

Net Income ..............................       $12,288    $ 16,040     $16,478
                                                =======    ========     =======

Average Common Shares Outstanding .......         8,781       8,598       8,432
                                                  =====       =====       =====

Basic Earnings per Share ................         $1.40       $1.87       $1.95
                                                  =====       =====       =====



       The accompanying notes are an integral part of these statements.


<PAGE>


                             COLONIAL GAS COMPANY
                         CONSOLIDATED BALANCE SHEETS

Assets                                             December 31,
(In Thousands)                                   1998       1997      
                                                 ----       ----      
Utility Property:
   At original cost                           $394,222    $362,742
   Accumulated depreciation                   (102,009)    (88,210)
                                              --------     ------- 
      Net Utility Property                     292,213     274,532
Non-Utility Property - Net                       7,129       7,312
                                                 -----       -----
      Net Property                             299,342     281,844

Capital Leases - Net                             1,583       2,630
                                                 -----       -----

Current Assets:
   Cash and cash equivalents                     3,125         259
   Accounts receivable                          14,591      21,788
      Allowance for doubtful accounts           (1,350)     (3,203)
   Accrued utility revenues                      7,876       7,417
   Unbilled gas costs                           18,195      19,266
   Fuel inventory - at average cost             12,712      12,959
   Materials and supplies - at average cost      2,906       2,950
   Prepayments and other current assets          9,513       6,531
                                                 -----       -----
      Total Current Assets                      67,568      67,967
                                                ------      ------

Deferred Charges and Other Assets:
   Unrecovered deferred income taxes             8,349       9,014
   Unrecovered demand side management costs      6,661       8,273
   Unrecovered environmental costs incurred      3,633       3,833
   Unrecovered environmental costs accrued         200         707
   Unrecovered pension costs                     3,307       3,455
   Unrecovered transition costs accrued            700       2,800
   Excess cost of investments over net 
     assets acquired                             2,798       2,798
   Other                                         6,863       5,670
                                                 -----       -----
      Total Deferred Charges and Other Assets   32,511      36,550
                                                ------      ------

Total Assets                                  $401,004    $388,991
                                              ========    ========


       The accompanying notes are an integral part of these statements.


<PAGE>


                             COLONIAL GAS COMPANY
                         CONSOLIDATED BALANCE SHEETS

Capitalization and Liabilities                     December 31,
(In Thousands)                                  1998        1997
------------------------------------------------------------------
Capitalization:
Common Equity:
   Common Stock                                $29,669     $28,931
   Premium on Common Stock                      63,080      57,277
   Retained earnings                            36,173      35,924
                                                ------      ------
      Total Common Equity                      128,922     122,132
Long-Term Debt                                 120,000     100,102
                                               -------     -------
      Total Capitalization                     248,922     222,234
                                               -------     -------
Long-Term Capital Lease Obligations                963       1,617
                                                   ---       -----

Current Liabilities:
   Current maturities of long-term debt            102      10,164
   Current capital lease obligations               620       1,013
   Notes payable                                52,000      49,400
   Gas inventory purchase obligations           14,125      14,895
   Accounts payable                             12,186      15,674
   Accrued interest                              2,698       2,375
   Current deferred income taxes                 3,830       3,654
   Other current liabilities                     4,022       5,333
                                                 -----       -----
      Total Current Liabilities                 89,583     102,508
                                                ------     -------

Deferred Credits and Reserves:
   Deferred income taxes - Funded               44,555      41,443
   Deferred income taxes - Unfunded              8,349       9,014
   Unamortized investment tax credits            3,072       3,372
   Pension reserve                               4,424       4,507
   Accrued environmental costs                     200         707
   Accrued transition costs                        700       2,800
   Other deferred credits and reserves             236         789
                                                   ---         ---
      Total Deferred Credits and Reserves       61,536      62,632
                                                ------      ------

Total Capitalization and Liabilities          $401,004    $388,991
                                              ========    ========


       The accompanying notes are an integral part of these statements.


<PAGE>


                             COLONIAL GAS COMPANY
                    CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                  Year Ended December 31,
(In Thousands)                                  1998      1997     1996
------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net Income                                     $12,288  $16,040  $16,478
Adjustments to reconcile net income to net cash:
   Depreciation and amortization                14,764   13,334   12,361
   Deferred income taxes                         3,157    3,208    7,968
   Amortization of investment tax credits         (300)    (300)    (268)
   Provision for uncollectable accounts           (601)   1,955    2,146
   Other, net                                     (227)     109      171
                                                  ----      ---      ---
                                                29,081   34,346   38,856
Changes in current assets and liabilities:
   Accounts receivable and accrued utility 
   revenues                                      5,486   (6,620)   2,305
   Unbilled gas costs                            1,071      (28)  (9,550)
   Fuel inventory                                  247   (1,001)  (1,442)
   Prepayments and other current assets         (2,938)   2,003   (4,015)
   Accounts payable                             (3,488)   1,130    2,394
   Other current liabilities                      (988)   2,645   (2,929)
                                                  ----    -----   ------ 
Net Cash Provided by Operating Activities       28,471   32,475   25,619
                                                ------   ------   ------
Cash Flows From Investing Activities:
   Utility capital expenditures                (31,093) (35,788) (26,875)
   Non-utility capital expenditures               (364)  (1,888)  (1,367)
   Change in deferred accounts                     972     (842)  (1,502)
                                                   ---     ----   ------ 
Net Cash Used in Investing Activities          (30,485) (38,518) (29,744)
                                               -------  -------  ------- 
Cash Flows From Financing Activities:
   Dividends paid on Common Stock              (12,039) (11,435) (10,919)
   Issuance of Common Stock                      6,541    3,621    3,277
   Issuance of long-term debt, net of 
     issuance costs                              39,11  614,871   29,787
   Retirement of long-term debt, including 
     premiums                                  (30,568)  (5,152) (11,284)
   Change in notes payable                       2,600   (1,000) (11,435)
   Change in gas inventory purchase obligations   (770)   1,856      699
                                                  ----    -----      ---
Net Cash Provided by Financing Activities        4,880    2,761      125
                                                 -----    -----      ---
Net Increase (Decrease) in Cash and Cash 
     Equivalents                                 2,866   (3,282)  (4,000)
Cash and Cash Equivalents at Beginning of Year     259    3,541    7,541
                                                   ---    -----    -----
Cash and Cash Equivalents at End of Year       $ 3,125  $   259  $ 3,541
                                               =======  =======  =======
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
   Interest - net of amount capitalized        $10,229  $ 9,465  $ 9,149
   Income and state franchise taxes            $ 7,238  $ 7,509  $ 8,489

       The accompanying notes are an integral part of these statements.


<PAGE>


                             COLONIAL GAS COMPANY
                   CONSOLIDATED STATEMENTS OF COMMON EQUITY

                                          Year ended December 31,
(In Thousands Except Per Share Amounts)    1998     1997     1996
                                           ----     ----     ----

Common Stock
   $3.33 par value; authorized 15,000 
     shares; outstanding, 8,910 in 1998, 
     8,688 in 1997, and 8,518 in 1996
   Beginning of year                     $28,931  $28,366  $27,863
     Issuance of Common Stock through
      Dividend  Reinvestment and Common 
          Stock Purchase Plan and 
          Employee savings plan (222 
          shares in 1998, 170 shares 
          in 1997 and 151
          shares in 1996)                    738      565      503
                    ----                     ---      ---      ---

   End of year                           $29,669  $28,931  $28,366
                                         -------  -------  -------

Premium on Common Stock
   Beginning of year                     $57,277  $54,221  $51,447
     Issuance of Common Stock through
      Dividend Reinvestment and Common
        Stock Purchase Plan and
        Employee savings plan              5,803    3,056    2,774
                                           -----    -----    -----

   End of year                           $63,080  $57,277  $54,221
                                         -------  -------  -------

Retained Earnings
   Beginning of year                     $35,924  $31,319  $25,760
     Net income                           12,288   16,040   16,478
     Cash dividends on Common Stock 
         ($1.37 a share in 1998, $1.33 
          a share in 1997 and $1.295 
          a share in 1996)               (12,039) (11,435) (10,919)
                     ----                -------  -------  ------- 

   End of year                           $36,173  $35,924  $31,319
                                         -------  -------  -------

        Total Common Equity             $128,922 $122,132 $113,906
                                        ======== ======== ========


       The accompanying notes are an integral part of these statements.






Notes to Consolidated Financial Statements

Note A:  Summary of Significant Accounting Policies

Nature of Operations - Colonial Gas Company, a Massachusetts  corporation formed
in 1849, is primarily a regulated natural gas distribution  utility. The Company
serves over 154,500 utility customers in 24 municipalities  located northwest of
Boston and on Cape Cod. Through its subsidiary,  Transgas Inc., the Company also
provides  over-the-road  transportation of liquefied  natural gas, propane,  and
other commodities.

Principles of Consolidation - The consolidated  financial statements include the
accounts of the Company and its subsidiaries.  All material  intercompany  items
have been eliminated in consolidation.

Use of Estimates - 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.

Utility  Regulation - The Company's utility operations are subject to regulation
by the Massachusetts  Department of  Telecommunications  & Energy ("DTE"),  with
respect to rates charged for natural gas sales and  transportation,  among other
things.  The  Company's  policies  conform with  generally  accepted  accounting
principles, as applied to regulated public utilities.

Utility  Property and  Non-Utility  Property - Utility  property and non-utility
property are stated at original  cost,  including  labor,  materials,  taxes and
overheads.  The amount of interest  capitalized  as a component of  construction
overheads amounted to $805,000,  $594,000,  and $437,000 in 1998, 1997 and 1996,
respectively.
      The original cost of depreciable  utility property retired,  together with
the cost of removal,  net of salvage,  is charged to  accumulated  depreciation.
Depreciation  applicable  to  the  Company's  utility  property  in  service  is
calculated  in  accordance  with  depreciation  rates as  approved by the DTE. A
composite  depreciation  rate of  approximately  3.8% is applied to the  utility
property  balance at the  beginning of each year.  Depreciation  on  non-utility
property is computed by various methods.

Operating Revenues - Operating revenues are accrued based upon the amount of gas
delivered to utility customers through the end of the accounting period. Accrued
utility  revenues of $7,876,000 and $7,417,000,  as reported in the Consolidated
Balance  Sheets at  December  31,  1998 and 1997,  respectively,  represent  the
accrual of unbilled  operating  revenues net of related gas costs. The Company's
policy is to record  lost  margins  and  financial  incentives  relating  to the
Company's demand side management  ("DSM") programs as revenue when earned by the
Company. (See Note I).

Unbilled Gas Costs - The Company  charges or credits its utility  customers  for
increases or decreases in gas costs from those  reflected in its base tariffs by
applying a cost of gas adjustment clause ("CGAC").  In accordance with the CGAC,
<PAGE>

any under or over  recoveries  of gas  costs  are  charged  or  credited  to the
unbilled  gas cost account and recorded as a current  asset or  liability.  Such
under or over recoveries are collected or refunded, with interest accrued at the
prime rate, in subsequent periods.

Pipeline Refunds Due Customers - The Company periodically  receives refunds from
interstate pipeline companies related to rate adjustments ordered by the Federal
Energy Regulatory Commission ("FERC"). Refunds are returned to utility customers
under methods approved by the DTE.

Excess  Cost  of  Investments  over  Net  Assets  Acquired  - This  asset  arose
principally   from  the  pre-1971   acquisitions  of  utility   operations.   No
amortization  has been provided since,  in the opinion of management,  there has
been no diminution in value of the applicable investments.

Income  Taxes - The Company  records  deferred  income  taxes for the income tax
effect  of the  difference  between  book  and tax  depreciation  and all  other
temporary book and tax  differences,  in accordance  with Statement of Financial
Accounting  Standards  No. 109  "Accounting  for  Income  Taxes"  ("SFAS  109").
Unamortized  investment tax credits, which were allowed under Federal income tax
laws prior to 1987,  have been  deferred and are being  amortized as a credit to
income tax expense over the estimated service lives of the corresponding assets.

Interest  and Debt  Expense - Interest  and debt  expense  includes  interest on
long-term debt, interest on short-term notes payable and regulatory interest. As
approved  by the  DTE,  regulatory  interest  is  interest  income  credited  on
regulatory assets or interest expense charged on regulatory liabilities.

Pension Plans - The Company and its  subsidiaries  have 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.

Cash and Cash Equivalents - For the purposes of the Consolidated  Balance Sheets
and Statements of Cash Flows,  the Company  considers cash  investments  with an
original maturity of three months or less to be cash equivalents.

Fair Value of Financial  Instruments - In accordance with Statement of Financial
Accounting  Standards  No.  107  "Disclosures  About  Fair  Values of  Financial
Instruments",  the fair value  amounts  are  disclosed  below.  These fair value
amounts are not  necessarily  indicative  of the amounts that the Company  could
realize in a current market exchange.
      The  carrying  amount of cash and cash  equivalents  and  short-term  debt
approximates  fair value. The fair value of long-term debt is estimated based on
the rates  available to the Company at the end of each  respective year for debt
of the  same  remaining  maturities.  The  carrying  amount  of  long-term  debt
(including current  maturities) was $120,102,000 and $110,266,000 as of December
31,  1998  and  1997,  respectively.  The  fair  value  of  long-term  debt  was
$129,302,000 and $115,700,000 as of December 31, 1998 and 1997, respectively.
<PAGE>

      Under  current  regulatory  treatment,  any  premiums  paid  to  refinance
long-term debt, would be recovered over the life of new debt, and would not have
a significant impact on the Company's results of operations.

     Earnings  Per  Share  -  The  Company  determines  earnings  per  share  in
accordance  with the provisions of Statement of Financial  Accounting  Standards
No. 128 "Earnings  Per Share"  ("SFAS  128").  Earnings per share in computed by
dividing net income by the average  number of common shares  outstanding  during
the  period.   The  Company  has  no  dilutive   shares.   Reclassifications   -
Reclassifications   are  made   periodically  to  previously   issued  financial
statements to conform to the current year presentation.
Note B:  Federal Income Tax

The  Company  records  deferred  income  taxes for the  income tax effect of the
difference  between book and tax  depreciation  and all other temporary book and
tax differences,  in accordance with SFAS 109. Prior to October 1981 as approved
by the DTE, the Company did not record  deferred income taxes but rather "flowed
through" tax benefits to utility  customers.  At December 31, 1998,  the Company
has a liability of  $8,349,000  on the  Consolidated  Balance  Sheet as Deferred
Income Taxes - Unfunded and a  corresponding  unrecovered  deferred  asset.  The
liability  represents the tax effect of pre-1981  timing  differences  for which
deferred income taxes had not been provided and was increased in accordance with
SFAS 109 for the tax  effect of future  revenue  requirements.  The  Company  is
recovering  these  unfunded  deferred  taxes  from  utility  customers  over the
remaining book life of utility property.

      Federal income tax expense is comprised of the following components:

                                         Year Ended December 31,
(In Thousands)                           1998       1997      1996
                                         ----       ----      ----
Charged (credited) to operations:
Current                                $4,396     $5,188    $1,104
Deferred:
   Accelerated depreciation             1,933      1,688     2,202
   Unbilled gas costs                     146        (98)    2,929
   Demand side management costs          (394)        88       747
   Pension costs                          124        301       449
   Recovery of unfunded deferred taxes    398        398       398
   Debt expense                           (53)       (53)      (53)
   Environmental response costs           (65)       (58)     (246)
   Bad debt                               355        889      (167)
   Miscellaneous                          (57)       221       (94)
Amortization of investment tax credits   (301)      (300)     (268)
                                         ----       ----      ---- 
      Total                             6,482      8,264     7,001
                                        -----      -----     -----
Charged (credited) to other income       (605)       312     1,599
                                         ----        ---     -----
      Total Federal income tax expense $5,877     $8,576    $8,600
                                       ======     ======    ======
<PAGE>


The effective  Federal income tax rate and the reasons for the  difference  from
the statutory Federal income tax rate are as follows:

                                            1998      1997     1996
                                            ----      ----     ----
Statutory Federal income tax rate            35%       35%      35%
Increases (reductions) in taxes resulting 
    from:
    Amortization of investment tax credits   (2)       (1)      (1)
    Recovery of unfunded deferred taxes       2         2        2
    Miscellaneous items                      (3)       (1)      (2)
                                             --        --       -- 
      Effective Federal income tax rate      32%       35%      34%
                                             ==        ==       == 

Temporary  differences  which  gave rise to the  following  deferred  tax assets
(liabilities) are:

                                         December 31,
(In Thousands)                        1998           1997
                                      ----           ----
Deferred Tax Assets:
Construction contributions      $      832     $      891
Other                                  222            227
                                       ---            ---
    Total deferred tax assets        1,054          1,118
                                     -----          -----

Deferred Tax Liabilities:
Accelerated depreciation           (43,662)       (41,345)
Unbilled gas costs                  (3,830)        (3,654)
Demand side management costs        (2,293)        (2,765)
Environmental response costs        (1,423)        (1,502)
Cost of removal                     (3,143)        (3,033)
Other                               (3,437)        (2,930)
    Total deferred tax liabilities (57,788)       (55,229)
                                   -------        ------- 
Total deferred taxes              $(56,734)      $(54,111)
                                  ========       ======== 

Note C:  Capital Stock

Pursuant to the Company's dividend  reinvestment and common stock purchase plan,
shareholders  can  automatically  reinvest  their cash  dividends and can invest
optional limited amounts of cash payments in newly issued shares.
   The Company has authorized  and unissued  547,559 shares of Class A Preferred
Stock,  $25 par value,  of which  100,000  shares have been  designated a Junior
Preferred Stock series and reserved for issuance under the Rights Plan described
below, and 370,000 shares of Class B Preferred Stock, $1 par value.
   A  Shareholder  Rights Plan  provides  one right  ("Right")  to purchase  one
one-hundredth  of a share  of the  Company's  Series  A-1  Junior  Participating
Preferred Stock,  par value $25 per share, at a price of $60 per share,  subject
to  adjustment.   The  Rights  expire  on  December  1,  2003  and  only  become
exercisable,  or  separately  transferable,  10 days  after a  person  or  group
acquires,  or announces an intention to acquire,  beneficial ownership of 20% or
more of the Company's  Common Stock. By vote of the Company's Board of Directors
on October  17,  1998,  rights are not  triggered  by the  Pending  Merger  with
Eastern.  The Rights are redeemable by the Board at a price of $.01 per Right at
any time prior to the  expiration of ten days after the  acquisition by a person
or group of beneficial ownership of 20% or more of the Company's Common Stock.
<PAGE>


Note D:  Long-Term Debt

The composition of long-term debt is as follows:
                           Maturity    Put            December 31,
(In Thousands)               Date      Date        1998        1997
                                                   ----        ----
First mortgage bonds:
    8.05%   Series CG      due 1999          $      ---     $ 20,000
    8.80%   Series CH      due 2022               25,000      25,000
    6.85%   Series MTA-1   due 2025    2005       10,000      10,000
    6.45%   Series MTA-2   due 2025    2005       10,000      10,000
    6.94%   Series MTA-3   due 2026               10,000      10,000
    6.20%   Series MTA-4   due 1998                 ---       10,000
    6.88%   Series MTA-5   due 2008               10,000      10,000
    6.81%   Series MTA-6   due 2027    2002       15,000      15,000
    6.38%   Series MTA-7   due 2008               10,000        ---
    6.86%   Series MTB-1   due 2028               20,000        ---
    5.50%   Series MTB-2   due 2003               10,000        ---
    ----               -       ----               ------           
          Total                                  120,000     110,000
Note payable                                         102         266
                                                     ---         ---
Less: Long-term debt due within one year            (102)    (10,164)

Total long-term debt                            $120,000    $100,102
                                                ========    ========

The aggregate  amount of maturities for the years 1999 through 2003 are $102,000
in 1999,  and  $10,000,000  in 2003.  Bonds  of  $15,000,000  due in 2027 can be
redeemed by the holder in 2002.
   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.  The  note  payable  is  collateralized  by
equipment.
   The Company has in place a medium term note ("MTN") program which permits the
issuance of up to $75 million of MTN's as bonds under its indenture of which $30
million  has been issued as of  December  1998.  The bonds with a put date noted
above  can be  redeemed  by  the  holder  within  a 30 day  period  in the  year
indicated.

Note E:  Short-Term Debt

In September  1997, the Company  established a three-year bank line of credit of
$75 million with a consortium of four banks which expires in September 2000. The
bank line of credit  allows the  Company  to borrow on a demand  basis up to $75
million,  less  whatever  amount has been  borrowed  through the  Company's  gas
inventory  trust  (described  below).  The line of credit allows the Company the
option to borrow under three alternative rates:  Eurodollar (LIBOR), prime, or a
competitive  bid option.  At December 31, 1998, the credit  available  under the
bank line of credit was  $8,875,000.  The weighted  average  interest  rates for
short-term   debt  were  5.80%  and  6.18%  at  December   31,  1998  and  1997,
respectively.
   The Company has an agreement with a single-purpose  Massachusetts  trust, the
Company's gas inventory  trust,  under which the Company sells  supplemental gas
inventory to the trust at the Company's  cost. The Company's  agreement with the
trust requires it to repurchase such inventory at cost when needed and reimburse
the trust for expenses incurred to finance the gas inventory. The trust finances
<PAGE>

such  purchases of  inventory  by  borrowing  under a bank line of credit with a
maximum  borrowing  commitment  of $30 million that is  complementary  to and on
similar terms as the Company's bank line of credit  described above. The DTE has
approved the inventory trust  arrangement and has permitted the cost of such gas
inventory,  including  fees and  financing  costs,  to be recovered  through the
Company's CGAC. During 1998, 1997 and 1996 approximately $620,000, $564,000, and
$500,000, respectively, of interest costs were incurred by the trust.

Note F:  Lease Obligations

The Company leases certain equipment used in its operations.  In accordance with
accounting for regulated public utilities,  the Company has capitalized  certain
of these leases and reflects  lease payments as rental expense in the periods to
which  they  relate.  This  capitalization  has no impact on the  Company's  net
income.
   Assets held under capital leases amounted to  approximately  $2,510,000,  and
$7,702,000  at December 31, 1998 and 1997,  respectively.  In 1998,  the Company
purchased  certain  facilities  used in its  operations  which  were  previously
leased. Accumulated amortization on assets held under capital leases amounted to
approximately   $927,000  and   $5,072,000   at  December  31,  1998  and  1997,
respectively.
   Total  rental  expense  for  the  years  1998,  1997  and  1996  approximated
$1,150,000 and $1,527,000, and $1,493,000,  respectively.  At December 31, 1998,
the future  minimum  payments  (including  interest)  under the Company's  lease
agreements are: $641,000 in 1999;  $489,000 in 2000;  $390,000 in 2001; $195,000
in 2002; $21,000 in 2003; and $0 thereafter.

Note G:  Employee Benefit Plans

Savings  Plan - The Company  sponsors  an  employee  401(k)  Savings  Plan.  The
Company's matching  contribution,  exclusive of plan  administration  costs, was
$689,000, $625,000 and $570,000 for 1998, 1997 and 1996, respectively.

Pension Plans - The Company and its  subsidiaries  have various  defined benefit
pension plans covering substantially all employees.

Net periodic pension cost is comprised of the following components:

                                             Year Ended December 31,
(In Thousands)                             1998        1997      1996
                                           ----        ----      ----

Service cost                             $1,220      $1,042    $1,036
Interest cost on projected benefit 
     obligation                           3,492       3,427     3,267
Expected return on plan assets           (4,170)     (6,711)   (4,710)
Net amortization and deferral               625       3,673     1,882
                                            ---       -----     -----
Net periodic pension cost                $1,167      $1,431    $1,475
                                         ======      ======    ======
 


<PAGE>


Assumptions used in actuarial calculations were as follows:

                                              Year Ended December 31,
                                           1998        1997       1996
                                           ----        ----       ----

Weighted average discount rate             7.00%       7.00%      7.75%
Future compensation increases              4.00%       4.00%      4.00%
Expected long-term rate of return on 
     assets                                9.50%       9.00%      9.00%



The  following  tables  set  forth  the  reconciliation  of the  plans'  benefit
obligation  and fair value of assets for the years ended  December  31, 1998 and
1997:

(In Thousands)                                  1998         1997
----------------------------------------------------------------------
Reconciliation of benefit obligation:
   Obligation at January 1                    $50,989      $45,016
      Service cost                              1,220        1,042
      Interest cost                             3,492        3,427
      Amendments                                  176         (497)
      Actuarial (gain) loss                       393        5,067
      Benefit payments                         (3,138)      (3,066)
                                               ------       ------ 
   Obligation at December 31                  $53,132      $50,989
                                               =======      =======


Reconciliation of fair value of plan assets:
   Fair value of plan assets at January 1     $48,332      $41,458
      Actual return on plan assets              5,161        7,583
      Employer contributions                    1,484        2,357
      Benefit payments                         (3,138)      (3,066)
                                               ------       ------ 
   Fair value of plan assets at December 31   $51,839      $48,332
                                              =======      =======



<PAGE>


The funded status of the plans at December 31, 1998 and 1997 is as follows:

                                           1998                   1997
                                   Assets  Accumulated      Assets  Accumulated
                                   Exceed     Benefits      Exceed     Benefits
                              Accumulated       Exceed Accumulated       Exceed
(In Thousands)                   Benefits       Assets    Benefits       Assets
--------------------------------------------------------------------------------

Projected benefit
obligations:
   Vested ......................   $(33,064)   $(12,823)   $(32,420)   $(12,020)
   Nonvested ...................       (952)     (1,194)       (828)     (1,088)
                                       ----      ------        ----      ------ 
Accumulated ....................    (34,016)    (14,017)    (33,248)    (13,108)
Due to recognition of future ...     (4,814)       (285)     (4,497)       (136)
                                     ------        ----      ------        ---- 
      salary increases
            Total ..............    (38,830)    (14,302)    (37,745)    (13,244)
Plan assets at fair value ......     41,050      10,789      38,765       9,567
                                     ------      ------      ------       -----
Projected benefit obligation
      less than (in excess of)..      
      plan assets                     2,220      (3,513)      1,020      (3,677)
Unrecognized net (gain) loss ...       (793)        895          78         729
Unrecognized transition amount .      1,048         699       1,223         331
Unrecognized prior service cost.        (33)      1,863         (60)      2,424
Additional liability accrued ...          -      (3,172)          -      (3,350)
                                      ------      ------     ------      ------ 
                                                         
Prepaid (accrued) pension costs    $  2,442    $ (3,228)   $  2,261    $ (3,543)
                                   ========    ========    ========    ======== 

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.

Postretirement   Life  and  Health  Benefit  Plan  -  The  Company   sponsors  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.
      During  1993,  the  Company  adopted  Statement  of  Financial  Accounting
Standards No. 106 "Employers' Accounting for Postretirement  Benefits Other Than
Pensions" ("SFAS 106"). Prior to 1993, expense was recognized when benefits were
paid. In accordance with SFAS 106, the Company began recording the cost for this
plan  on an  accrual  basis  in  1993.  The  Company  amortizes  the  transition
obligation  over a twenty-year  period.  The Company's  cost under this plan for
1998,  1997  and 1996 was  $509,000,  $410,000,  and  $501,000, respectively.  A
regulatory  asset of $431,000  was recorded in 1993  representing  the excess of
postretirement  benefits  on the  accrual  basis over the paid  amounts  for the
period of January 1, 1993 until  November  1, 1993,  the  effective  date of the
DTE's  approval  of  the  Company's  new  rates.   Currently,   the  DTE  allows
Massachusetts   utilities  to  recover  the  tax  deductible  portion  of  these
postretirement 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.



<PAGE>


The  following  tables  set  forth  the  reconciliation  of the  plans'  benefit
obligation  and fair value of plan assets for the years ended  December 31, 1998
and 1997:

(In Thousands)                                  1998         1997
----------------------------------------------------------------------
Reconciliation of benefit obligation:
   Obligation at January 1                     $7,179       $6,229
      Service cost                                138          113
      Interest cost                               534          477
      Amendments                                 (314)           0
      Actuarial (gain) loss                     1,272          685
      Benefit payments                           (251)        (325)
                                                 ----         ---- 
   Obligation at December 31                   $8,558       $7,179
                                               ======       ======


Reconciliation of fair value of plan assets:
   Fair value of plan assets at January 1      $5,163       $4,614
      Actual return on plan assets                527          779
      Employer contributions                        0           95
      Benefit payments                           (251)        (325)
                                                 ----         ---- 
   Fair value of plan assets at December 31    $5,439       $5,163
                                               ======       ======

   The following  table sets forth the plan's funded status  reconciled with the
amounts  recognized in the Company's  financial  statements at December 31, 1998
and 1997:

(In Thousands)                                   1998        1997
----------------------------------------------------------------------
Accumulated postretirement benefit
obligation:
         Retirees                             $(4,579)     $(4,564)
         Fully eligible active plan            (1,767)      (1,192)
            participants
         Other active plan participants        (2,212)      (1,423)
                                               ------       ------ 
      Total                                    (8,558)      (7,179)
Plan assets at fair value                       5,439        5,163
                                                -----        -----
Accumulated postretirement benefit
obligation                                     (3,119)      (2,016)
      in excess of plan assets
Unrecognized net (gain) from past experience
      different from that assumed and from
      changes in assumptions                     (193)      (1,351)
Unrecognized transition obligation              3,481        4,045
                                                -----        -----
Prepaid postretirement benefit cost           $   169      $   678
                                              =======      =======



<PAGE>


Net periodic postretirement benefit cost included the following components:

                                                 Year Ended December 31,
(In Thousands)                               1998        1997        1996
----------------------------------------------------------------------------
Service cost - benefits attributable
to service                                   $138        $113        $137
      during the period
Interest cost on accumulated
postretirement                                534         477         461
      benefit obligation
Expected return on plan assets               (412)       (375)       (507)
Net amortization and deferral                 249         195         410
                                              ---         ---         ---
Net periodic postretirement benefit          $509        $410        $501
                                             ====        ====        ====
cost

   For  measurement  purposes,  a 6% (4.5%  for  dental  costs)  annual  rate of
increase in the per capita cost of covered  health care benefits was assumed for
1999;  the rate of increase for medical costs was assumed to decrease  gradually
to 4.5% for 2002 and remain at that level thereafter. The health care cost trend
rate assumption has a significant effect on the amounts reported. To illustrate,
increasing the assumed  health care cost trend rates by one percentage  point in
each year would increase the accumulated postretirement benefit obligation as of
December  31,  1998 by  $1,175,000  and the  aggregate  of the  service  and the
interest  cost  components of net periodic  postretirement  benefit cost for the
year then ended by $111,000.
   The  weighted  average  discount  rate used in  determining  the  accumulated
postretirement  benefit  obligation was 7.0%, 7.0%, and 7.75% for 1998, 1997 and
1996,  respectively.  The expected  long-term  rate of return on plan assets was
9.5%, 9.0%, and 9.0% for 1998, 1997, and 1996,  respectively,  for assets in the
Section 401(h) accounts and, after estimated  taxes,  was 6.25%,  6.0%, and 6.0%
for 1998,  1997,  and 1996,  respectively,  for assets in the Section  501(c)(9)
trust.


Note H:  Other Commitments

Long-Term Obligations - The Company has contracts, which expire at various dates
through the year 2013, for the  acquisition and delivery of gas supplies and the
storage and delivery of natural gas stored  underground.  The contracts  contain
minimum  payment  provisions  which  correspond  to gas  purchases  that, in the
opinion of management, are not in excess of the Company's requirements.

FERC Order 636  Transition  Costs - As a result of FERC Order 636, the Company's
interstate  pipeline  service  providers  have been  required to unbundle  their
supply and  transportation  services.  This unbundling has caused the interstate
pipeline companies to incur substantial costs in order to comply with Order 636.
These  transition costs include four types: (1) unrecovered gas costs (gas costs
that had been  incurred but not yet  recovered by the  pipelines  when they were
providing  bundled  service  to local  distribution  companies);  (2) gas supply
realignment costs (the cost of renegotiating  existing gas supply contracts with
producers);  (3)  stranded  costs  (unrecovered  costs of assets that can not be
assigned to customers  of  unbundled  services);  and (4) new  facilities  costs
(costs of new facilities required to physically implement Order 636).
   Pipelines are allowed to recover  prudently  incurred  transition  costs from
customers such as the Company, primarily through a demand charge, after approval
<PAGE>

by FERC. The Company's  additional  transition cost liabilities are estimated to
be  approximately  $700,000.  The  Company is  recovering  these  costs from its
customers,  as approved by the DTE in October 1994. As of December 31, 1998, the
Company  has  recorded on the balance  sheet a long-term  liability  of $700,000
("Accrued  Transition  Costs")  and,  based upon  expected  rate  recovery,  has
recorded  a  regulatory  asset  of  $700,000   ("Unrecovered   Transition  Costs
Accrued").  Actual  transition  costs to be incurred depends on various factors,
and therefore future costs may differ from the amounts discussed above.

Note I:  Contingencies

The  Company is  involved in various  legal  actions  and claims  arising in the
normal course of business. Management does not believe the outcome of any action
or claim  will have a  material  adverse  effect  upon the  Company's  financial
position or results of operations.
   Working with the Massachusetts  Department of Environmental  Protection,  the
Company is engaged in site  assessments  and evaluation of remedial  options for
contamination that has been attributed to the Company's former gas manufacturing
site and at various  related  disposal  sites.  During 1990,  the DTE ruled that
Colonial and eight other  Massachusetts  gas distribution  companies can recover
environmental response costs related to former gas manufacturing operations over
a seven-year period,  without carrying costs, through the CGAC. Through December
31, 1998, the Company had incurred  environmental  response costs of $12,582,000
of which $8,949,000 has been recovered from customers to date.
   As of December  31,  1998,  the Company has  recorded on the balance  sheet a
long-term  liability of $200,000 and,  based upon expected  rate  recovery,  has
recorded a corresponding  regulatory  asset.  This amount  represents  estimated
future response costs for these sites based on the Company's  preferred  methods
of remediation.  Actual  environmental  response costs to be incurred depends on
various factors, and therefore future costs may differ from the amount currently
recorded as a liability.
   In 1998, the DTE conducted an industry-wide  proceeding on 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 Company has been
using a calculation  method,  approved by the DTE in previous individual Company
filings, based on the useful life of installed conservation measures. As of this
date, the DTE has not yet issued its decision in the  industry-wide  proceeding.
The decision  could result in a  shortening  of the time period for  calculating
lost DSM  margins to less than the full  useful life of  installed  measures.  A
shortening  of the period would result in some  decrease in operating  revenues,
but it is  uncertain  at this time  whether or by how much the  period  would be
shortened and, therefore, what impact it would have on the Company.




<PAGE>


Note J:  Quarterly Financial Data (Unaudited)
(In Thousands Except Per Share Amounts)                    Basic
                                    Utility               Earnings   Dividends
                                   Operating      Net      (Loss)     Paid Per
                       Operating    Income      Income       Per        Common
Quarter Ended          Revenues     (Loss)      (Loss)      Share        Share
1998
December 31            $52,125      $7,773      $5,060     $.57          $.345
September 30            12,347      (3,246)     (5,213)    (.59)          .345
June 30                 25,684         256      (1,771)    (.20)          .345
March 31                77,822      16,075      14,212     1.63           .335

1997
December 31            $62,275      $9,481      $7,814     $.90          $.335
September 30            14,877      (3,043)     (4,566)    (.53)          .335
June 30                 26,927        (556)     (2,501)    (.29)          .335
March 31                83,061      16,974      15,293     1.79           .325

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.  The Company typically reports profits during
the first and fourth  quarters of each year while  incurring  losses  during the
second and third quarters. This is due to significantly higher natural gas sales
during the colder months to satisfy customers' heating needs.

Note K:  Merger

     On October 17, 1998,  the Company  entered  into an  Agreement  and Plan of
Reorganization (the "Merger Agreement") with Eastern Enterprises ("Eastern"),  a
Massachusetts  business  trust  which owns all of the  outstanding  stock of two
other  Massachusetts  LDC's,  Boston Gas  Company  ("Boston  Gas") and Essex Gas
Company  ("Essex  Gas").  The Merger  Agreement  provides  for the merger of the
Company with and into a subsidiary of Eastern,  as a result of which the Company
will  become a  wholly-owned  subsidiary  of  Eastern  (the  "Pending  Merger").
Pursuant to the Pending Merger,  the outstanding  shares of the Company's common
stock would  convert into the right to receive cash and Eastern  common stock as
set  forth  in  the  Merger  Agreement.  The  Pending  Merger  was  approved  by
shareholders of Colonial and Eastern at separate  special  shareholder  meetings
which were held on  February  10,  1999.  Completion  of the  Pending  Merger is
subject to receipt of satisfactory  regulatory approvals,  including approval of
the Massachusetts  Department of  Telecommunications  and Energy, the Securities
and Exchange Commission, and antitrust clearance.

<PAGE>


Report of Independent Certified Public Accountants


To the Shareholders of Colonial Gas Company

We have audited the  accompanying  consolidated  balance  sheets of Colonial Gas
Company  and  subsidiaries  as of December  31,  1998 and 1997,  and the related
consolidated statements of income, cash flows, and common equity for each of the
three years in the period 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 audits.
   We  conducted  our audits in  accordance  with  generally  accepted  auditing
standards.  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 the significant  estimates made by
management,  as well as evaluating the overall financial statement presentation.
We believe 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  consolidated  financial  position of Colonial Gas
Company and  subsidiaries as of December 31, 1998 and 1997, and the consolidated
results of their  operations and their  consolidated  cash flows for each of the
three years in the period ended December 31, 1998, in conformity  with generally
accepted accounting principles.



Boston, Massachusetts                                 s/Grant Thornton LLP
January 15, 1999                                      Grant Thornton LLP


<PAGE>



REPORT OF MANAGEMENT

To the Shareholders of Colonial Gas Company

Management is  responsible  for the  preparation  and integrity of the Company's
financial statements.  The financial statements have been prepared in accordance
with generally  accepted  accounting  principles as applied to regulated  public
utilities and  necessarily  include some amounts that are based on  management's
best estimates and judgment.
   The  Company  maintains a system of internal  accounting  and  administrative
controls  and an ongoing  program of internal  audits that  management  believes
provide  reasonable  assurance that assets are safeguarded and that transactions
are   properly   recorded   and  executed  in   accordance   with   management's
authorization.  The  Company's  financial  statements  have been  audited by the
independent  public  accounting  firm,  Grant  Thornton LLP, who also conducts a
review of  internal  controls  to the  extent  required  by  generally  accepted
auditing standards.
   The Audit  Committee of the Board of  Directors,  composed  solely of outside
directors,  meets with management,  internal  auditors and Grant Thornton LLP to
review  planned audit scope and results and to discuss  other matters  affecting
internal   accounting   controls  and  financial   reporting.   The  independent
accountants and internal  auditors have direct access to the Audit Committee and
periodically meet with its members without management representatives present.


s/F. L. Putnam, III                 s/Nickolas Stavropoulos

F. L. Putnam, III                   Nickolas Stavropoulos
President and Chief Executive       Executive Vice President-Finance,
Officer                             Marketing and Chief Financial Officer




<PAGE>




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

      None.

                                    PART III

Item 10. Directors and Executive Officers of the Registrant.

   The  information  required to be reported  hereunder  pursuant to Item 401 of
Regulation S-K for the Company's  Directors is  incorporated by reference to the
information  in the  Company's  definitive  Proxy  Statement for its 1999 annual
meeting of  stockholders  under the  caption  "INFORMATION  ABOUT  NOMINEES  AND
INCUMBENT DIRECTORS".

   The  information  required to be reported  hereunder  pursuant to Item 401 of
Regulation S-K for the Executive  Officers of the Registrant is  incorporated by
reference  to the  information  in Item 1A of this Form 10-K  under the  caption
"Executive Officers of the Registrant".

   The  information  required to be reported  hereunder  pursuant to Item 405 of
Regulation S-K is  incorporated by reference to the information in the Company's
definitive Proxy Statement for its 1999 annual meeting of stockholders under the
caption "SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE".

Item 11. Executive Compensation.

   The  information  required  to  be  reported  hereunder  is  incorporated  by
reference to the information in the Company's definitive Proxy Statement for its
1999 annual meeting of stockholders under the captions "EXECUTIVE  COMPENSATION"
and under the subheading  "Directors'  Compensation" of the caption "INFORMATION
ABOUT NOMINEES AND INCUMBENT DIRECTORS".


<PAGE>



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

   The  information  required  to  be  reported  hereunder  is  incorporated  by
reference to the information in the Company's definitive Proxy Statement for its
1999 annual meeting of  stockholders  under the caption  "SECURITY  OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT".


Item 13. Certain Relationships and Related Transactions.

   The  information  required  to  be  reported  hereunder  is  incorporated  by
reference to the information in the Company's definitive Proxy Statement for its
1999  annual  meeting of  stockholders  under the  captions  "INFORMATION  ABOUT
NOMINEES AND INCUMBENT DIRECTORS" and "EXECUTIVE COMPENSATION".

                                    PART IV

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

(a)   1. Financial  Statements 
          
         The list of Financial Statements filed as part
         of this Form 10-K Report is set forth in Item 8 on page 23.

      2. Financial  Statement Schedules 

         The Financial  Statement  Schedules and report  thereon  required  to
         be filed as part of this Form 10-K Report  are as follows:

Schedule                                                             Page
Number              Description                                     Number

            Report of Independent Certified Public Accountants 
            on Schedule                                               49

   II       Valuation and Qualifying Accounts for the three 
            years ended December 31, 1998                             50

Schedules  other  than  those  listed  above  are  either  not  required  or not
applicable,  or the required information is shown in the financial statements or
notes thereto.  Columns  omitted from schedules  filed have been omitted because
the information is not applicable.


<PAGE>



      3. List of Exhibits

 Exhibit
Number               Exhibit                               Reference


  2     Agreement and Plan of Reorganization   Incorporated herein
        by and between Eastern Enterprises     by reference.
        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.

  3a    Restated Articles of Organization of   Incorporated herein
        Colonial Gas Company dated April 19,   by reference.
        1989, as amended on July 16, 1992 and
        supplemented by a certificate of vote
        of Directors establishing a series of
        a class of stock filed on November
        30, 1993, filed as Exhibit 3(a) to
        the Registrant's Annual Report on
        Form 10-K for the fiscal year ended
        December 31, 1993.

  3b    By-Laws of Colonial Gas Company, as    Incorporated herein
        amended to date, filed as Exhibit      by reference.
        3(b) to the Registrant's Annual
        Report on Form 10-K for the fiscal
        year ended December 31, 1996.

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

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

  4c    Second Supplemental Indenture dated    Incorporated herein
        as of September 27, 1995, filed as     by reference.
        Exhibit 4(c) to the Registrant's Form
        10-K for the fiscal year ended
        December 31, 1995.

  4d    Amendment to Second Supplemental       Incorporated herein
        Indenture dated as of October 12,      by reference.
        1995, filed as Exhibit 4(d) to the
        Registrant's Form 10-K for the fiscal
        year ended December 31, 1995.

  4e    Third Supplemental Indenture dated as  Incorporated herein
        of December 15, 1995, filed as         by reference.
        Exhibit 4f to the Registrant's Form
        S-3 Registration Statement dated
        January 5, 1998.

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

  4g    Form of Rights Agreement dated as of   Incorporated herein
        December 1, 1993, between Colonial     by reference.
        Gas Company and BankBoston, N.A.
        (f/k/a/ The First National Bank of
        Boston), as Rights Agent, together
        with the following exhibits thereto:
        (i) Form of Vote Establishing the
        Series A-1 Junior Participating
        Preferred Stock, (ii) Form of Rights
        Certificate, and (iii) Summary of
        Rights to Purchase Preferred Shares.
        Filed as Exhibit 1 to the
        Registrant's Registration Statement
        on Form 8-A filed on November 22,
        1993 (File No. 0-10007).
<PAGE>

  4h    Amendment to Rights Agreement between  Filed herewith as
        Colonial Gas Company and BankBoston,   Exhibit 4h.
        N.A. dated as of October 17, 1998.

  4i    Revolving Credit Agreement for         Incorporated herein
        Colonial Gas Company dated as of       by reference.
        September 12, 1997, filed as Exhibit
        4(e) to Form 10-Q of the Registrant
        for the quarter ended September 30,
        1997.

  4j    Revolving Credit Agreement for         Incorporated herein
        Massachusetts Fuel Inventory Trust     by reference.
        dated as of September 12, 1997, filed
        as Exhibit 4(f) to Form 10-Q of the
        Registrant for the quarter ended
        September 30, 1997.

  4k    Purchase Contract dated as of June     Incorporated herein
        27, 1990 between Massachusetts Fuel    by reference.
        Inventory Trust acting by and through
        its Trustee, Shawmut Bank, N.A. and
        Colonial Gas Company, filed as
        Exhibit 10(e) to Form 8-K of the
        Registrant for quarter ended June 30,
        1990.

  4l    Security Agreement and Assignment of   Incorporated herein
        Contracts dated as of September 12,    by reference.
        1997 made by Massachusetts Fuel
        Inventory Trust in favor of Fleet
        National Bank as Agent for designated
        banks, filed as Exhibit 4(h) to Form
        10-Q of the Registrant for the
        quarter ended September 30, 1997.

  4m    Trust Agreement dated as of June 22,   Incorporated herein
        1990 between Colonial Gas Company (as  by reference.
        Trustor) and Shawmut Bank, N.A. (as
        Trustee), filed as Exhibit 10(d) to
        Form 8-K of the Registrant for
        quarter ended June 30, 1990.

  10a   Form Employment Agreement dated as of  Incorporated herein
        October 13, 1998, for Colonial Gas     by reference.
        Company corporate officers, filed as
        Exhibit 10.l to the Registrant's Form
        10-Q for the quarter ended September
        30, 1998.

  10b   Employment Agreement dated as of       Incorporated herein
        October 13, 1998, by and between       by reference.
        Colonial Gas Company, Transgas Inc.
        and V.W. Baur, filed as Exhibit 10.2
        to the Registrant's Form 10-Q for the
        quarter ended September 30, 1998.

  10c   Colonial Gas Company Retention Bonus   Incorporated herein
        Plan, effective as of October 19,      by reference.
        1998, filed as Exhibit 10.3 to the
        Registrant's Form 10-Q for the
        quarter ended September 30, 1998.

  10d   Rate increase deferral incentive       Incorporated herein
        policy of Colonial Gas Company dated   by reference.
        January 1, 1995, filed as Exhibit
        10(xx) to the Registrant's Form 10-K
        for the fiscal year ended December
        31, 1994.

  10e   1997 Transitional Executive Incentive  Incorporated herein
        Plan of Colonial Gas Company, filed    by reference.
        as Exhibit 10e to the Registrant's
        Form 10-K for the fiscal year ended
        December 31, 1997.
<PAGE>

  10f   Colonial Gas Company Executive         Incorporated herein
        Performance and Equity Incentive Plan  by reference.
        included as Appendix A to the Proxy
        Statement for the Company's 1998
        Annual Meeting and to the Prospectus
        included in the Registration
        Statement on Form S-4 of the
        Company's subsidiary, Colonial
        Energy, filed on March 6, 1998.
        (Commission File No. 333-47441.)

  21a   Subsidiaries of the Registrant.        Filed herewith as

  23a   Consent of Independent Certified       Filed herewith as
        Public Accountants.                    Exhibit 23a.



   Exhibits 10a through 10f above are management contracts or compensatory plans
   or arrangements in which the executive officers of the Company participate or
   participated during time periods covered by this Form 10-K Report.


(b) Reports on Form 8-K.
   As  reported  on the Form 8-K filed by the Company  with the  Securities  and
   Exchange  Commission on October 21, 1998, the Company and Eastern Enterprises
   entered into an Agreement and Plan of Reorganization  dated October 17, 1998,
   a copy of which was filed as an Exhibit to that Form 8-K.



<PAGE>




      REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS ON SCHEDULE







To the Shareholders of
Colonial Gas Company


In  connection  with  our  audit of the  consolidated  financial  statements  of
Colonial Gas Company and  subsidiaries  referred to in our report dated  January
15, 1999,  which is included in Part II of this Form 10-K,  we have also audited
the schedule  listed at Part IV, Item  14(a)2.  In our  opinion,  this  schedule
presents fairly, in all material  respects,  the information  required to be set
forth therein.



                                          GRANT THORNTON LLP

Boston, Massachusetts
January 15, 1999


<PAGE>



SCHEDULE II

                      COLONIAL GAS COMPANY AND SUBSIDIARIES
                        VALUATION AND QUALIFYING ACCOUNTS
                   For the Three Years Ended December 31, 1998
                                 (In Thousands)


COLUMN A                       COLUMN B    COLUMN C      COLUMN D      COLUMN E
                                           ADDITIONS
                                           CHARGED
                               BALANCE AT  TO COSTS                   BALANCE AT
                               BEGINNING   AND                        END OF
DESCRIPTION                    OF PERIOD   EXPENSES      DEDUCTIONS   PERIOD

                      For the Year Ended December 31, 1998

Reserve for uncollectable      $3,203      $   537       $1,253 (1)     $1,350
accounts                       ======      =======       ====== ==      ======
                                                         $1,137 (2)
                                                         ====== == 
                                                            

Reserve for insurance claims   $1,593       $  237      $   422         $1,408
                               ======       ======      =======         ======

                      For the Year Ended December 31, 1997

Reserve for uncollectable      $2,715       $1,956       $1,468 (1)     $3,203
 accounts                      ======       ======       ====== ==      ======
                                              

Reserve for insurance claims   $1,486      $   675      $   568         $1,593
                               ======      =======      =======         ======

                      For the Year Ended December 31, 1996

Reserve for uncollectable      $2,205       $2,127       $1,617 (1)     $2,715
accounts                       ======       ======       ====== ==      ======
                                              

Reserve for insurance claims   $1,233       $  836       $  583         $1,486
                               ======       ======       ======         ======

-----------------------------
(1)   Accounts charged off, net of collections.
(2)   Transfer of gas cost  portion of reserve as of  November  1, 1998,  
      based on unbundling of rates



<PAGE>


                                  SIGNATURES

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

                              COLONIAL GAS COMPANY                Date

                              By s/F.L. Putnam, Jr.        February 24, 1999
                              F. L. Putnam, Jr., Chairman
                              of the Board of Directors

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

           Signature                     Title                    Date

s/F. L. Putnam, Jr.        Senior Executive Officer,       February 24, 1999
F. L. Putnam, Jr.          Director

s/Nickolas Stavropoulos   Executive Vice President -       February 24, 1999
Nickolas Stavropoulos     Finance, Marketing and Chief
                          Financial Officer, Director 
                          (Principal Financial Officer)

s/D. W. Carroll           Vice President and Treasurer     February 24, 1999
D. W. Carroll             (Principal Accounting Officer)

s/V.W. Baur               Director                         February 24, 1999
V.W. Baur

s/J. P. Harrington        Director                         February 24, 1999
J. P. Harrington
  
s/H. C. Homeyer           Director                         February 24, 1999
H. C. Homeyer

s/R. L. Hull              Director                         February 24, 1999
R. L. Hull

s/R. A. Perkins           Director                         February 24, 1999
R. A. Perkins

s/F. L. Putnam, III       President and Chief              February 24, 1999
F. L. Putnam, III         Executive Officer, Director

s/J. F. Reilly, Jr.       Director                         February 24, 1999
J. F. Reilly, Jr.
   
s/A. B. Sides, Jr.        Director                         February 24, 1999
A. B. Sides, Jr
  
s/M. M. Stapleton         Director                         February 24, 1999
M. M. Stapleton

<PAGE>

INDEX TO EXHIBITS INCLUDED HEREWITH

4h    Amendment to Rights Agreement between  
      Colonial Gas Company and BankBoston,   
      N.A. dated as of October 17, 1998.

21a   Subsidiaries of the Registrant.        

23a   Consent of Independent Certified       
      Public Accountants.