[EXHIBIT 13a TO COLONIAL GAS COMPANY
              10-K FOR YEAR ENDED DECEMBER 31, 1997]
                                 
                                 
CONSOLIDATED STATEMENTS OF INCOME

(In Thousands Except Per Share Amounts) Year Ended December 31,
                                        1997     1996    1995

Operating Revenues                   $187,140 $169,878 $163,668
Cost of gas sold                      102,455   87,188   83,631
  Operating Margin                     84,685   82,690   80,037
Operating Expenses:
  Operations                           30,044   30,372   30,410
  Maintenance                           4,503    4,476    4,401
  Depreciation and amortization        12,049   11,228   10,225
  Local property taxes                  3,139    3,189    3,020
  Other taxes                           2,122    2,183    2,130
   Total Operating Expenses            51,857   51,448   50,186
Income Taxes:
  Federal income tax                    8,264    7,001    6,879
  State franchise tax                   1,708    2,087    1,447
   Total Income Taxes                   9,972    9,088    8,326
Utility Operating Income               22,856   22,154   21,525
Other Operating Income (Expense):
  Energy Trucking revenues              5,529   11,031    7,576
  Energy Trucking expenses, including
   income taxes and interest           (5,202)  (9,005)  (6,972)
   Energy Trucking Net Income             327    2,026      604
  Other, net of income taxes              318      250       41
   Total Other Operating Income           645    2,276      645
Non-Operating Income, Net of Income Taxes 573      757      864
Income Before Interest and 
   Debt Expense                        24,074   25,187   23,034
Interest and Debt Expense               8,034    8,709    9,270
Net Income                            $16,040  $16,478  $13,764

Average Common Shares Outstanding       8,598    8,432    8,294

Income per Average Common Share         $1.87    $1.95    $1.66



The accompanying notes are an integral part of these statements.

CONSOLIDATED BALANCE SHEETS

Assets                                    December 31,
(In Thousands)                          1997     1996
Utility Property:
  At original cost                   $362,742  $333,319
  Accumulated depreciation            (88,210)  (82,336)
  Net Utility Property                274,532   250,983
Non-Utility Property - Net              7,312     5,925
  Net Property                        281,844   256,908

Capital Leases - Net                    2,630     1,811

Current Assets:
Cash and cash equivalents                 259     3,541
Accounts receivable                    21,788    17,719
  Allowance for doubtful accounts      (3,203)   (2,715)
Accrued utility revenues                7,417     6,333
Unbilled gas costs                     19,266    19,238
Fuel inventory - at average cost       12,959    11,958
Materials and supplies - 
   at average cost                      2,950     2,891
Prepayments and other current assets    6,531     8,593

  Total Current Assets                 67,967    67,558

Deferred Charges and Other Assets:
Unrecovered deferred income taxes       9,014     9,774
Unrecovered demand side management 
  costs                                 8,273     7,075
Unrecovered environmental costs 
   incurred                             3,833     4,011
Unrecovered environmental costs accrued   707     1,183
Unrecovered pension costs               3,455     3,135
Unrecovered transition costs accrued    2,800     4,500
Excess cost of investments over 
   net assets acquired                  2,798     2,798
Other                                   5,670     5,659
  Total Deferred Charges and 
   Other Assets                        36,550    38,135
Total Assets                         $388,991  $364,412

CONSOLIDATED BALANCE SHEETS

Capitalization and Liabilities            December 31,
(In Thousands)                          1997      1996
Capitalization:
Common Equity:
Common Stock                         $ 28,932   $28,366
Premium on Common Stock                57,277    54,221
Retained earnings                      35,923    31,319
     Total Common Equity              122,132   113,906
Long-Term Debt                        100,102    95,266
     Total Capitalization             222,234   209,172
Capital Lease Obligations               1,617       930

Current Liabilities:
Current maturities of long-term debt   10,164     5,152
Current capital lease obligations       1,013       881
Notes payable                          49,400    50,400
Gas inventory purchase obligations     14,895    13,039
Accounts payable                       15,674    14,544
Accrued interest                        2,375     1,815
Current deferred income taxes           3,654     5,090
Other current liabilities               5,333     3,248
     Total Current Liabilities        102,508    94,169

Deferred Credits and Reserves:
Deferred income taxes - Funded         41,443    35,886
Deferred income taxes - Unfunded        9,014     9,774
Accrued environmental costs               707     1,183
Accrued transition costs                2,800     4,500
Unamortized investment tax credits      3,372     3,672
Pension reserve                         4,507     4,174
Other deferred credits and reserves       789       952
     Total Deferred Credits and 
        Reserves                       62,632    60,141
Total Capitalization and Liabilities $388,991  $364,412


The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS
                                       Year Ended December 31,
(In Thousands)                          1997    1996     1995
Cash Flows From Operating Activities:
Net Income                            $16,040  $16,478  $13,764
Adjustments to reconcile net income 
   to net cash:
  Depreciation and amortization        13,334   12,361   11,211
  Deferred income taxes                 3,208    7,968    1,159
  Amortization of investment tax 
     credits                             (300)    (268)    (275)
  Provision for uncollectible accounts  1,955    2,146    1,829
  Other, net                              109      171      973
                                       34,346   38,856   28,661

Changes in current assets and liabilities:
  Accounts receivable and accrued 
     utility revenues                  (6,620)   2,305   (9,293)
  Unbilled gas costs                      (28)  (9,550)   2,490
  Fuel inventory                       (1,001)  (1,442)   2,443
  Prepayments and other current assets  2,003   (4,015)   5,612
  Accounts payable                      1,130    2,394    2,515
  Other current liabilities             2,645   (2,929)    (920)
Net Cash Provided by Operating 
   Activities                          32,475   25,619   31,508
Cash Flows From Investing Activities:
 Utility capital expenditures         (35,788) (26,875) (24,096)
 Non-utility capital expenditures      (1,888)  (1,367)  (1,974)
 Change in deferred accounts             (842)  (1,502)  (2,077)
Net Cash Used in Investing Activities (38,518) (29,744) (28,147)
Cash Flows From Financing Activities:
 Dividends paid on Common Stock       (11,435) (10,919) (10,571)
 Issuance of Common Stock               3,622    3,277    2,702
 Issuance of long-term debt, net 
    of issuance costs                  14,870   29,787   19,685
 Retirement of long-term debt, 
    including premiums                 (5,152) (11,284) (27,477)
 Change in notes payable               (1,000) (11,435)  12,335
 Change in gas inventory 
    purchase obligations                1,856      699   (1,520)
Net Cash Provided by (Used in) 
Financing Activities                    2,761      125   (4,846) 
Net Decrease in Cash and Cash 
   Equivalents                         (3,282)  (4,000)  (1,485)
Cash and Cash Equivalents at 
   Beginning of Year                    3,541    7,541    9,026
Cash and Cash Equivalents at 
   End of Year                          $ 259  $ 3,541  $ 7,541
Supplemental Disclosures of Cash 
   Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized  $ 9,465   $9,149  $ 9,867
Income and state franchise taxes      $ 7,509   $8,489  $ 3,444

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF COMMON EQUITY

                                         Year ended December 31,
(In Thousands Except Per Share Amounts)   1997    1996    1995

Common Stock
  $3.33 par value; authorized 15,000 
  shares; outstanding, 8,688 in 1997, 
  8,518 in 1996, and 8,367 in 1995
  Beginning of year                     $28,366  $27,863  $27,397
   Issuance of Common Stock through
     Dividend Reinvestment and Common
      Stock Purchase Plan and
      Employee savings plan (170 shares
      in 1997, 151 shares in 1996 
      and 140 shares in 1995)               566      503      466

  End of year                           $28,932  $28,366  $27,863

Premium on Common Stock
  Beginning of year                     $54,221  $51,447  $49,211
   Issuance of Common Stock through
     Dividend Reinvestment and Common
      Stock Purchase Plan and
      Employee savings plan               3,056    2,774    2,236

  End of year                           $57,277  $54,221  $51,447

Retained Earnings
  Beginning of year                     $31,319  $25,760  $22,567
   Net income                            16,040   16,478   13,764
   Cash dividends on Common 
      Stock ($1.33 a share in 
      1997, $1.295 a share in
      1996 and $1.275 a share 
      in 1995)                          (11,435) (10,919) (10,571)

  End of year                           $35,923  $31,319  $25,760

      Total Common Equity              $122,132 $113,906 $105,070


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  151,000  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"),  formerly  known  as   the
Massachusetts  Department  of Public Utilities,  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  $594,000,
$437,000, and $568,000 in 1997, 1996 and 1995, 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 $7,417,000 and
$6,333,000,  as  reported in the Consolidated  Balance  Sheets  at
December 31, 1997 and 1996, 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  and
approved by the DTE.

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, 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 $110,266,000 and $100,418,000 as of  December  31,
1997  and 1996, respectively. The fair value of long-term debt  was
$115,700,000  and $102,000,000 as of December 31,  1997  and  1996,
respectively.

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

Impairment of Long-Lived Assets - During 1996, the Company adopted
Statement  of  Financial Accounting Standards No. 121  "Accounting
for  the Impairment of Long-Lived Assets and Long-Lived Assets  to
be  Disposed  Of". This statement requires the Company  to  review
long-lived  assets for impairment whenever events  or  changes  in
circumstances indicate that the carrying amount of  an  asset  may
not  be recoverable. The adoption of this standard did not have  a
material impact on the Company's financial condition or results of
operations.

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, 1997, the  Company
has a liability of $9,014,000 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)                   1997     1996     1995
Charged (credited) to 
   operations:
Current                        $5,188   $1,104   $6,422
Deferred:
  Accelerated depreciation      1,688    2,202    2,005
  Unbilled gas costs              (98)   2,929   (1,523)
  Demand side management costs     88      747      (32)
  Pension costs                   301      449      (38)
  Recovery of unfunded 
     deferred taxes               398      398      398
  Debt expense                    (53      (53)     848
  Transition costs                 --       (1)    (871)
  Environmental Response Costs    (58)    (246)      22
  Bad debt                        889     (167)    (175)
  Miscellaneous                   221      (93)      96
Amortization of investment tax 
   credits                       (300)    (268)     273
     Total                      8,264    7,001    6,879
Charged to other income           312    1,599      510
     Total Federal income 
        tax expense            $8,576   $8,600   $7,389

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

                                     1997     1996    1995

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

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

                                 December 31,
(In Thousands)                 1997       1996
Deferred Tax Assets:
Construction contributions    $ 891    $    974
Other                           227         335
   Total deferred tax assets  1,118       1,309

Deferred Tax Liabilities:
Accelerated depreciation    (41,345)    (39,580)
Unbilled gas costs           (3,654)     (3,990)
Demand side management costs (2,765)     (2,659)
Environmental response costs (1,502)     (1,571)
Cost of removal              (3,033)     (2,792)
Other                        (2,930)     (1,467)
   Total deferred tax 
   liabilities              (55,229)    (52,059)
Total deferred taxes       $(54,111)   $(50,750)

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. 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.

Note D:  Long-Term Debt

The composition of long-term debt is as follows:
                        Maturity  Put         December 31,
   (In Thousands)       Date      Date      1997       1996
First mortgage bonds:
   9.40%  Series CE     due 1997          $     -  $   5,000
   8.05%  Series CG     due 1999           20,000     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     10,000
   6.88%  Series MTA-5  due 2008           10,000     10,000
   6.81%  Series MTA-6  due 2027  2002     15,000          0
        Total                             110,000    100,000
Note payable                                  266        418
Less: Long-term debt due within one year  (10,164)    (5,152)

Total long-term debt                     $100,102    $95,266

The aggregate amount of maturities for the years 1998 through 2002
are  $10,164,000  in  1998, and $20,102,000  in  1999.   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 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 $65 million has been issued as of December 1997.
The bonds with a put date noted above can be redeemed by the holder
within a 30 day period in the year indicated.

   Interest  Rate  Instruments:  - The  Company  has  entered  into
treasury  rate locks in order to hedge the interest rate  on  long-
term debt anticipated to be issued in early 1998. The treasury rate
locks  are for $10 million at a 10 year treasury rate of 5.88%  and
for  $20 million at a 15 year treasury rate of 5.88%. Upon issuance
of  the debt, any gain or loss realized on the treasury rate  locks
will  be amortized to interest expense over the term of the related
debt.

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 five banks. 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: based on eurodollar rate (LIBOR), prime  rate,
or  a  competitive  bid option. At December 31, 1997,  the  credit
available  under  the  bank line of credit  was  $10,705,000.  The
weighted average interest rates for short-term debt were 6.18% and
5.87% at December 31, 1997 and 1996, 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 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 1997,  1996  and
1995  approximately $564,000, $500,000 and $662,000, respectively,
of interest  costs were incurred by the trust.

Note F:  Lease Obligations

The  Company leases certain facilities and 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
$7,703,000  and  $7,685,000  at  December  31,  1997   and   1996,
respectively.  Accumulated  amortization  on  assets  held   under
capital leases amounted to approximately $5,072,000 and $5,874,000
at December 31, 1997 and 1996, respectively.

   The  most  significant agreements which meet the  criteria  for
capital lease classification are a lease which expires in 1998 for
a   liquefied   natural  gas  storage  tank  in  South   Yarmouth,
Massachusetts  and  a  lease  which expires  in  2002  for  office
facilities in Lowell, Massachusetts. Both leases have fair  market
renewal options at the end of their initial terms.

   Total  rental  expense  for  the  years  1997,  1996  and  1995
approximated  $1,527,000, $1,493,000 and $1,429,000, respectively.
At  December  31,  1997,  the future minimum  payments  (including
interest) under the Company's lease agreements are: $1,069,000  in
1998;  $749,000  in  1999;  $619,000 in 2000;  $544,000  in  2001;
$201,000 in 2002; 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 $625,000, $570,000  and  $459,000  for
1997, 1996 and 1995, 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)                        1997      1996    1995

Benefits earned during the period   $1,042    $1,036  $  836
Interest cost on projected 
   benefit obligation                3,427     3,267   3,279
Actual return on plan assets        (6,711)   (4,710) (5,515)
Net amortization and deferral        3,673     1,882   2,757
Net periodic pension cost           $1,431    $1,475  $1,357

Assumptions used in actuarial calculations were as follows:

                                     Year Ended December 31,
                                     1997      1996     1995

Weighted average discount rate       7.00%     7.75%    7.50%
Future compensation increases        4.00%     4.00%    4.00%
Expected long-term rate of return 
on assets                            9.00%     9.00%    9.00% 

The funded status of the plans at December 31, 1997 and 1996 is as
follows: 
                              1997                      1996
                          Assets Accumulated       Assets Accumulated
                          Exceed    Benefits       Exceed    Benefits
                     Accumulated      Exceed  Accumulated      Exceed
(In Thousands)          Benefits      Assets     Benefits      Assets      
                                                      
Projected benefit                                     
obligations:
  Vested               $(32,420)   $(12,020)    $(28,612)   $(10,381)
  Nonvested                (828)     (1,088)        (703)       (956)
Accumulated             (33,248)    (13,108)     (29,315)    (11,337)
Due to recognition of                                          
future salary increases  (4,497)       (136)      (4,248)       (116)
          Total         (37,745)    (13,244)     (33,563)    (11,453)
Plan assets at fair      38,765       9,567       33,743       7,715
value
Projected benefit                                              
obligation                1,020      (3,677)         180      (3,738)
     less than (in 
     excess of)
     plan assets
Unrecognized net (gain)      78         729         (457)        188
     loss
Unrecognized              1,223         331        1,398       2,020
transition amount
Unrecognized prior          (60)      2,424          487       1,064
service cost
Additional liability                                           
accrued                       -      (3,350)           -      (3,157)
Prepaid (accrued)          
pension costs            $2,261    $ (3,543)    $  1,608      (3,623)

Assets of the employee benefit plans are invested in domestic  and
international   equities,  medium-term   domestic   fixed   income
securities, 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 1997, 1996  and  1995  was  $410,000,
$501,000 and $672,000 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 a trust under Section  501(c)(9)
of  the  Internal Revenue Code and separate accounts of the  trust
under Section 401(h) of the Internal Revenue Code.

      The  following  table  sets forth the plan's  funded  status
reconciled with the amounts recognized in the Company's  financial
statements at December 31, 1997 and 1996:

(In Thousands)                      1997       1996
                                             
Accumulated postretirement                   
benefit obligation:
     Retirees                     $(4,564)   $(3,957)
     Fully eligible active plan    
        participants               (1,192)    (1,033)
     Other active plan             
        participants               (1,423)    (1,239)
     Total                         (7,179)    (6,229)
Plan assets at fair value           5,163      4,563
Accumulated postretirement                   
     benefit obligation            
     in excess of plan assets      (2,016)    (1,666)
Unrecognized net (gain) from                 
     past experience different 
     from that assumed and from 
    changes in assumptions         (1,351)    (1,679)
Unrecognized transition         
obligation                          4,045      4,315
Prepaid postretirement benefit    
cost                                $ 678      $ 970


Net  periodic  postretirement benefit cost included the  following
components:

                                Year Ended December 31,
(In Thousands)                  1997      1996      1995
                                                    
Service cost - benefits                             
attributable to service         $113      $137      $145
     during the period
Interest cost on accumulated                        
postretirement                   477       461       505
     benefit obligation
Actual return on plan assets    (779)     (507)     (639)
Net amortization and deferral    599       410       661
Net periodic postretirement     $410      $501      $672
benefit 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 1998; the rate of increase  for  medical
costs  was  assumed  to decrease gradually to 4.5%  for  2001  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,  1997  by
$979,000  and  the aggregate of the service and the interest  cost
components  of net periodic postretirement benefit  cost  for  the
year then ended by $81,000.

      The  weighted average discount rate used in determining  the
accumulated postretirement benefit obligation was 7.0%, 7.75%  and
7.5% for 1997, 1996 and 1995, respectively. The expected long-term
rate  of  return on plan assets was 9% for assets in  the  Section
401(h)  accounts and, after estimated taxes, was 6% for assets  in
the Section 501(c)(9) trust for all years presented.


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  expected  to be allowed  to  recover  prudently
incurred  transition  costs from customers such  as  the  Company,
primarily  through a demand charge, after approval  by  FERC.  The
Company's additional transition cost liabilities are estimated  to
range  from  $2,800,000 to $3,300,000. The Company  is  recovering
these  costs from its customers, as approved by the DTE in October
1994.  As  of December 31, 1997, the Company has recorded  on  the
balance  sheet  a  long-term  liability  of  $2,800,000  ("Accrued
Transition  Costs")  and, based upon expected rate  recovery,  has
recorded a regulatory asset of $2,800,000 ("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, 1997,  the
Company  had  incurred environmental response costs of $11,875,000
of which $8,042,000 has been recovered from customers to date.

  As of December 31, 1997, the Company has recorded on the balance
sheet  a  long-term liability of $707,000 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.


Note J:  Quarterly Financial Data (Unaudited)
(In Thousands Except Per Share Amounts)        Income
                           Utility           (Loss) Per   Dividends
                          Operating     Net    Average     Paid Per
                Operating   Income     Income   Common       Common
Quarter Ended    Revenues   (Loss)     (Loss)   Share         Share
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
1996
December 31       $53,612  $9,289     $7,035      $.83      $.325
September 30       14,983  (2,613)    (3,580)     (.42)      .325
June 30            23,973    (714)    (2,205)     (.26)      .325
March 31           77,310  16,192     15,228      1.82       .320

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.


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, 1997  and
1996,  and  the  related consolidated statements of  income,  cash
flows, and common equity for each of the three years in the period
ended  December  31,  1997.  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, 1997 and 1996, and the consolidated results of  their
operations and their consolidated cash flows for each of the three
years  in  the period ended December 31, 1997, in conformity  with
generally accepted accounting principles.



                                             GRANT THORNTON LLP


Boston, Massachusetts
January 14, 1998

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.


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

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Net Income and Dividends

Net  income  and income per average common share were  $16,040,000
($1.87),  $16,478,000  ($1.95), and $13,764,000  ($1.66)  for  the
years ended December 31, 1997, 1996, and 1995, respectively.

  Net income was favorably impacted by colder than 20-year average
temperatures  in  1997,  1996  and 1995.  This  is  summarized  as
follows:
                                          1997    1996   1995
Percent colder than 20-year average       1.8%    3.0%   2.4%

Percent colder (warmer) than prior year  (1.2)%   0.6%  (2.5)%

Other items which had an impact on net income are discussed in the
following sections.

   Dividends paid per common share were $1.33 in 1997,  $1.295  in
1996  and  $1.275 in 1995. The Company has paid dividends  for  61
consecutive years, and has increased dividends each year  for  the
past 18 years.


Operating Revenues

Operating revenues were $187,140,000 in 1997, $169,878,000 in 1996
and  $163,668,000 in 1995. 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),  formerly known as the Massachusetts Department  of
Public  Utilities, and the pass-through of gas costs to  customers
via a cost of gas adjustment clause ("CGAC").

   The volumes of gas sold are affected by fluctuations in weather
and the number of customers being served. Firm customers increased
by  14,900 over the last three years from 136,700 in December 1994
to  151,600  in  December 1997, an increase of 10.9%.   The  chart
below summarizes volumes of gas sold and transported and number of
firm customers:

                                       1997    1996     1995
(In MMcf)
Gas sold
   Firm                              19,997   19,56  318,560
   Non-Firm                              62     648    1,148
Gas transported
   Firm                               3,278   3,918    2,537
   Non-Firm                           3,791   2,671    3,224
         Total gas sold and 
            transported (In MMcf)    27,128  26,800   25,469

Firm Customers                      151,600 145,400  141,400

   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, which offset weather which was 1.2% warmer  than
the prior year.

   Operating revenues increased $6,210,000, or 3.8% from  1995  to
1996.  This  increase resulted from weather that was  0.6%  colder
than the prior year and customer growth of 2.9%.

Cost of Gas Sold

Average cost of gas sold per Mcf was $5.08 in 1997, $4.29 in  1996
and  $4.22  in  1995.  Cost of gas sold is based  upon  the  sales
volumes,  the price and mix of gas purchased and used  to  satisfy
demand,  and  profits on non-firm sales and transportation,  which
flow back to firm sales customers as a credit through the CGAC.

     The Company distributes natural gas purchased under long-term
contracts  as  well  as  gas purchased on  the  spot  market.  The
following  table  summarizes the sources of gas purchased  by  the
Company:

(In MMcf)                                1997    1996    1995
Gas purchased
  Pipeline                             14,763  15,115  14,659
  Underground storage                   3,605   3,346   3,270
  LNG/Other                             2,365   2,596   2,426
     Total gas purchased               20,733  21,057  20,355

Underground storage consists primarily of spot gas purchased and
injected into storage during the summer and fall for use during
the following winter.

Operating Expenses

Operations expense was $30,044,000 in 1997, a decrease of $328,000
or  1.1%,  from  1996,  and $30,372,000 in  1996,  a  decrease  of
$38,000, or 0.1%, from 1995.

   Maintenance  expense increased $27,000, or 0.6%, in  1997  from
1996 and increased $75,000, or 1.7%, in 1996 from 1995.

  Depreciation and amortization expense increased $821,000 or 7.3%
in  1997 and $1,003,000 or 9.8% in 1996. The increases in 1997 and
1996 were due to increases in utility property.

   Local property and other taxes decreased 2.1% in 1997 from 1996
due  to  reduced  property taxes. Local property and  other  taxes
increased 4.3% in 1996 from 1995. The increase in 1996 was due  to
higher  property taxes and additional property subject to property
taxes.

Income Taxes

Total  Federal income and state franchise taxes increased $884,000
or  9.7% in 1997 from 1996 and increased $762,000 or 9.2% in  1996
from  1995 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 $645,000
in  1997, $2,276,000 in 1996 and $645,000 in 1995. Other operating
income  primarily  includes the results of the  Company's  wholly-
owned  energy  trucking subsidiary (Transgas). Also  included  are
heating and water heating equipment sales and installations.

   Transgas' 1997 financial results were driven by a 50%  decrease
in  liquefied  natural gas ("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.

   Transgas' 1996 financial results were driven by a 68%  increase
in  LNG  hauls leading to a $3,455,000 increase in energy trucking
revenue  and a $1,422,000 increase in energy trucking net  income.
This increase in demand of transportation of LNG occurred for most
of  the  year  and  was primarily due to the  colder  than  normal
weather  in  the fourth quarter of 1995 and the first  quarter  of
1996.

   Factors 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

Non-operating income, net of income taxes, was $573,000  in  1997,
$757,000  in  1996  and  $864,000 in  1995.  Non-operating  income
includes interest income and miscellaneous other income.

Interest and Debt Expense

Interest and debt expense decreased $675,000 or 7.7% in 1997  from
1996.  The decrease in 1997 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.
Interest and debt expense decreased $561,000 or 6.1% in 1996.  The
decrease  in  1996 was due to a decrease in interest on  long-term
debt  resulting from the early retirement of higher interest  debt
in  December  1995 offset by increased levels of short-term  debt,
although at lower short-term interest rates.

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. The Company has set a goal to defer its next base  rate
increase until at least the year 2000.

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. On July 18, 1997, the DTE directed  the  Company
and  the  other  investor-owned gas utilities in Massachusetts  to
collaborate  on  developing common principles  to  unbundle  their
services  to provide customers with broader supplier choice.   The
DTE  further directed that all gas utilities have unbundled  rates
in effect by November 1, 1998 for all customer classes.

   Unbundled  service  separates  (i)  the  part  of  the  service
involving  procuring the gas and transporting it to the  city-gate
(i.e.  the  point where the Company takes gas from the  interstate
pipeline into its distribution systems); and (ii) the delivery  of
the  gas to the customer's facility through the local distribution
system.  The  Company  presently offers an  unbundled  service  to
commercial  and  industrial  customers  who  seek  to  have  other
suppliers  procure their gas which the Company  then  delivers  to
them  through its distribution system. The Company's proposal  for
further rate unbundling is being developed and is expected  to  be
filed  in  the spring of 1998.  In addition, the Company continues
to  participate in the DTE-directed Unbundling Collaborative.  The
Company cannot predict the outcome of the unbundling collaborative
process  or the other regulatory changes that may take place,  but
at  this time, the Company does not anticipate that the unbundling
of  its  services  will have a material financial  impact  on  its
business.

    Under   the   present  regulatory  system,  the  DTE   permits
Massachusetts gas companies to utilize a CGAC through  which  firm
sales  customers  pay,  via  their monthly  gas  bill,  the  costs
incurred by the companies in procuring and transporting gas to the
companies  distribution systems. Changes in non-gas or base  rates
charged  to  customers are subject to approval by  the  DTE  after
formal proceedings.

   Environmental response costs, transition costs and demand  side
management ("DSM") program costs are recovered through  the  CGAC,
as approved by the DTE. The environmental response costs recovered
through  the CGAC relate to the Company's former gas manufacturing
operations, as described under "Environmental Matters". Transition
costs  relate  to  Federal Energy Regulatory  Commission  ("FERC")
approved pipeline charges resulting from Order 636. In addition to
full  recovery of the installed conservation measures, the Company
is  allowed to recover, under methodologies approved in  1995  for
its  residential DSM programs and in 1996 for its  commercial  and
industrial   programs   resulting  lost  margins   and   financial
incentives based on the attainment of performance goals.

   The  Company has made only two requests for base rate increases
since  1984. Its most recent request was made in 1993. In response
to  that  request, the DTE approved a base rate increase that  was
designed  to produce additional revenues of $6.7 million  or  3.9%
annually, effective November 1, 1993.  Based upon continued strong
customer  growth,  cost  control and  improved  productivity,  the
Company's goal remains to postpone the filing of a request for its
next  base  rate  increase until at least  the  year  2000,  while
maintaining  an  adequate  return to shareholders.  Under  a  1995
industry  wide ruling of the DTE, the Company will be required  in
its  next  base  rate  filing  either to  present  an  alternative
incentive  based  method of pricing or to justify continuation  of
the traditional cost of service/rate of return method.

  On the same July 18, 1997 date that the DTE issued its directive
to  the  Massachusetts investor-owned gas utilities to collaborate
on  unbundling their services, the DTE issued its order  declining
to  approve  the Company's proposed joint venture with  Cabot  LNG
Corporation.   The  proposed  joint venture  would  have  combined
certain  LNG assets and resources of the two companies,  including
the   Company's  Tewksbury  LNG  facility  and  its  LNG  trucking
subsidiary, Transgas Inc.  The DTE's decision declining to approve
the  joint  venture  appeared to be based in  large  part  on  its
unwillingness  to  allow  a supply asset like  the  Tewksbury  LNG
facility  to  be  used  as proposed until the  issues  related  to
unbundling were resolved.

   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.

Environmental Matters

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, 1997,  the
Company  had  incurred environmental response costs of $11,875,000
of which $8,042,000 has been recovered from customers to date.

  As of December 31, 1997, the Company has recorded on the balance
sheet  a  long-term liability of $707,000 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.

Accounting Standards

Impairment of Long-Lived Assets - During 1996, the Company adopted
Statement  of  Financial Accounting Standards No. 121  "Accounting
for  the Impairment of Long-Lived Assets and Long-Lived Assets  to
be  Disposed  Of". This statement requires the Company  to  review
long-lived  assets for impairment whenever events  or  changes  in
circumstances indicate that the carrying amount of  an  asset  may
not  be recoverable. The adoption of this standard did not have  a
material impact on the Company's financial condition or results of
operations.

The Year 2000 Issue

The Company's principal computer systems are currently capable  of
processing  the year 2000 or are in the process of being  upgraded
or  replaced  by systems that are similarly capable.  The  Company
does  not  expect  the cost of addressing this  issue  to  have  a
material impact on the Company's financial results.

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
$35,788,000 in 1997, $26,875,000 in 1996 and $24,096,000 in  1995.
The   Company's   long-range  plan  calls   for   annual   utility
expenditures,  of  which over 52% is budgeted  for  new  business,
averaging $28,000,000 over the next five years as follows:


                                                              
(In Thousands)           1998     1999      2000     2001     2002
                                                          
Distribution          $22,500  $23,100   $23,800  $24,700  $25,600
Production              1,800      100       400      300      900
Information Systems     5,000    3,100     2,400      500      400
Automated Meter         
   Reading              3,100      300       300      300      200
General                   300      300       300      300      300
     Total Capital 
        Expenditures  $32,700  $26,900   $27,200  $26,100  $27,400
    


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

(In Thousands)                     1997      1996      1995
Common Stock Under Dividend 
   Reinvestment and Common Stock 
   Purchase Plan and Employee 
   Savings Plan                  $3,621    $3,277    $2,702
  Medium term notes under 
     the first mortgage 
     indenture                  $15,000   $30,000   $20,000

   The  aggregate amount of maturities of Long-Term Debt  for  the
years  1998  through 2002 are $10,164,000 in 1998, and $20,102,000
in  1999.  Series MTA-6 Bonds due in 2027 can be redeemed  by  the
holder  in 2002. The Company has entered into treasury rate  locks
in  order to hedge the interest rate on long-term debt anticipated
to  be  issued in early 1998. The treasury rate locks are for  $10
million at a 10-year treasury rate of 5.88% and for $20 million at
a 15-year treasury rate of 5.88%.

   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 the end of the year is shown in the table below:

                                        1997    1996   1995
Equity                                   55%     54%    58%
Long-Term Debt                           45%     46%    42%

   As  of April 1997, the quarterly dividend paid on the Company's
Common  Stock  was increased to $.335 per share or  an  annualized
dividend rate of $1.34 per share.

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 condition, increased competition and other uncertainties,
all  of  which  are difficult to predict, and many  of  which  are
beyond the control of the Company.

FINANCIAL AND OPERATING STATISTICS
(For the Years Ending 
December 31)           1997      1996       1995     1994      1993
Operating 
   Revenues
  (In Thousands)
Residential         $121,649   $108,879  $103,991  $104,812  $106,362
Commercial and 
   industrial         59,163     54,324    52,926    56,358    53,933
Firm transportation    1,941      1,843     1,294     1,210       816
Non-firm sales         2,530      2,985     3,745     2,429     3,613
Non-firm 
   transportation        631        453       424       401       409
Other                  1,226      1,394     1,288     1,017       233
     Total operating 
        revenues    $187,140   $169,878  $163,668  $165,327  $165,366

Gas Sold (MMcf)
Residential           12,492     12,094    11,361    11,190    11,492
Commercial and 
   industrial          7,505      7,469     7,199     7,526     7,443
Non-firm                  62        648     1,148       729     1,030
     Total gas 
       sales          20,059     20,211    19,708    19,445    19,965
Gas Transported (MMcf) 
Firm                   3,278      3,918     2,537     6,090     4,163
Non-firm               3,791      2,671     3,224     4,185     4,026
     Total gas 
       transported     7,069      6,589     5,761    10,275     8,189
     Total gas sold 
       and trans-
       ported         27,128     26,800    25,469    29,720    28,154
Gas Purchased (MMcf)
Pipeline              14,763     15,115    14,659    14,392    14,983
Underground storage    3,605      3,346     3,270     3,112     3,501
LNG - as liquid          680      1,067       844     1,129       907
LNG - as vapor         1,680      1,528     1,574     1,236       917
Propane                    5          1         8        25         8
     Total gas 
       purchased      20,733     21,057    20,355    19,894    20,316
Company use and 
   other                (674)      (846)     (647)     (449)     (351)
     Available for  
       sale           20,059     20,211    19,708    19,445    19,965
Customers - End of
  period
Residential          136,826    131,286   127,419   123,077   118,918
Commercial and 
   industrial         14,697     14,136    13,940    13,559    13,269
Firm transportation       30         19        11         8         1
Non-firm sales            22         25        27        21        21
Non-firm transportation   15          5         2         2         2
  Total customers - 
   end of period     151,590    145,471   141,399   136,667   132,211
Average Annual Mcf 
   Sold/Customer
Residential               96         96        94        96       101
Commercial and 
   industrial            519        533       531       569       575
Average Annual 
   Bill/Customer
Residential             $935       $868      $858      $897      $939
Commercial and 
   industrial         $4,093     $3,880    $3,901    $4,260    $4,167
Average Revenue/Mcf
Residential            $9.74      $9.00     $9.15     $9.37     $9.26
Commercial and 
   industrial          $7.88      $7.27     $7.35     $7.49     $7.25
Residential Heating 
   Customers as a
   % of all Residential 
   Customers             91%        90%       90%       90%       90%
Highest Daily 
   Sendout (Mcf)     183,063    170,984   199,275   204,896   184,303
Percent Colder 
   (Warmer) than 
   20-year average      1.8%       3.0%      2.4%      5.0%      6.3% 

SELECTED FINANCIAL DATA

(For the Years Ending December 31)
(In Thousands Except 
Per Share Amounts)         1997      1996       1995     1994      1993

Balance Sheet Data:
Assets:
Utility property - net  $274,532  $250,983   $235,555 $221,685  $202,713
Non-utility property 
   - net                   7,312     5,925      5,036    3,479     3,235
Capital leases - net       2,630     1,811      2,253    2,948     3,914
Current assets            67,967    67,558     61,002   65,568    67,668
Deferred charges and 
   other assets           36,550    38,135     38,575   37,668    34,588
     Total              $388,991  $364,412   $342,421 $331,348  $312,118
Capitalization and 
   Liabilities:
Capitalization:
Common equity           $122,132  $113,906   $105,070 $ 99,175  $ 94,283
Long-term debt           100,102    95,266     75,418   77,923    87,432
     Total 
       Capitalization    222,234   209,172    180,488  177,098   181,715
Capital lease obligations  1,617       930      1,359    2,237     3,149
Current liabilities      102,508    94,169    101,666   91,382    73,413
Deferred credits and 
   reserves               62,632    60,141     58,908   60,631    53,841
     Total              $388,991  $364,412   $342,421 $331,348  $312,118

Income Statement Data:
Operating revenues      $187,140  $169,878   $163,668 $165,327  $165,366
Cost of gas sold        (102,455)  (87,188)   (83,631) (87,458)  (90,915)
Operating margin          84,685    82,690     80,037   77,869    74,451
Operating expenses 
   (including income 
    taxes)               (61,829)  (60,536)   (58,512) (60,331)  (55,736)
Utility operating income  22,856    22,154     21,525   17,538    18,715
Other income - net of 
   income taxes            1,218     3,003      1,509    1,880     1,448
Interest and debt 
   expense                (8,034)   (8,709)    (9,270)  (8,409)   (8,141)
Accounting change              -         -          -        -         -
Net income               $16,040  $ 16,478    $13,764  $11,009  $ 12,022

Capitalization Ratios:
Common equity                55%       54%        58%      56%       52%
Long-term debt               45%       46%        42%      44%       48%
Common Stock Data:
Average shares 
   outstanding             8,598     8,432      8,294    8,119     7,931
Income per share           $1.87     $1.95      $1.66    $1.36(a)  $1.52
Dividends paid per share:
  Common Stock             $1.33    $1.295     $1.275   $1.255    $1.235
  Class A Common Stock         -         -          -        -         -
  Per weighted average 
     common share          $1.33    $1.295     $1.275   $1.255    $1.235
Dividend payout rate         71%       66%       77%       92%       81%
Book value per share      $14.06    $13.37    $12.56    $12.05    $11.74
Dividends as a percent 
   of book value              9%       10%       10%       10%       11%
Market price per share    $28.81    $21.25    $20.25    $19.25    $22.50
Market price as a 
   percent of book value    205%      159%      161%      160%      192%
Return on average common 
   equity                  13.6%     15.1%     13.5%     11.4%     13.2% 

(a) 1994 is after a restructuring charge of $.24 per share.
(b) 1988 includes the cumulative effect of an accounting 
    change of $.33 per share.

                          SHAREHOLDER INFORMATION

Corporate Headquarters
Colonial Gas Company
40 Market Street
P. O. Box 3064
Lowell, MA 01853-3064
(978) 322-3000
FAX: (978) 459-2314
www.colonialgas.com

Annual Meeting
The  Annual Meeting of Stockholders will be held on  April
15,  1998 at 10:00 a.m. at BankBoston, 100 Federal Street,
Boston, Massachusetts.

Stock Listing
The  Company's Common Stock began trading on the New  York
Stock  Exchange  under the symbol "CLG" on  September  18,
1997. Prior to that date, the Company traded on the NASDAQ
Stock  Market  under  the  symbol  "CGES".  Stock  trading
activity  is reported in financial publications under  the
abbreviation of ColonlGas or ColnlGa.
Annual Report - Form 10-K
A copy of the Company's 1997 Annual Report on Form 10-K as
filed with the Securities and Exchange Commission will  be
sent  free  of charge to any shareholder who contacts  the
Investor    Relations   Department   at   the    corporate
headquarters   address  above.   Many  of  the   Company's
financial statements are also available on its website.

Transfer Agent
BankBoston, N.A.
c/o Boston EquiServe, L.P.
P. O. Box 8040
Mail Stop: 45-02-64
Boston, MA  02266-8040
(800) 736-3001
(781) 575-3100

Independent Certified Public Accountants
Grant Thornton LLP
98 North Washington Street
Boston, MA  02114
(617) 723-7900

Corporate Counsel
Palmer & Dodge LLP
One Beacon Street
Boston, MA 02108
(617) 573-0100

Dividends
The  Company  has paid dividends on Common  Stock  for  61
consecutive  years and has increased dividends  each  year
for  the past 18 years. Common Stock dividends are payable
if and when declared by the Board of Directors.

Anticipated Record Date        Anticipated Payment Date
February 27, 1998              March 13, 1998
June 1, 1998                   June 15, 1998
September 1, 1998              September 15, 1998
December 1, 1998               December 15, 1998

Dividend Reinvestment Plan
The  Company's  Dividend  Reinvestment  and  Common  Stock
Purchase  Plan  ("DRIP") provides shareholders  of  record
with  an  economical and convenient method for  purchasing
additional  shares of the Company's Common  Stock  without
paying any brokerage fees.
 Participants in the plan may elect to purchase additional
Colonial shares at a 5% discount from the market price  by
reinvesting  all or a portion of their dividends  with  no
brokerage  fees. Participants in the plan  may  also  make
optional  cash  purchases of Common Stock  at  the  market
price  in  amounts  ranging from a minimum  of  $10  to  a
maximum  of $5,000 per calendar quarter, with no brokerage
fees.
   Features of the plan at no charge to shareholders
include:

 - Direct deposit of dividends by electronic deposit

 - Automatic  monthly  investments  by  electronic   funds
   transfer

 - Safekeeping of stock certificates

  Additional information describing the plan, including  a
prospectus and enrollment information, can be obtained  by
contacting  the  Company's  Transfer  Agent  or   Investor
Relations Department.

Investment Dates
The  investment  date for optional cash investments  under
the  DRIP will be the fifteenth day of each month  or,  if
that  day  is  not a business day, the preceding  business
day.  Optional  cash investments must be received  by  the
Company's  Transfer Agent five business  days  before  the
investment  date. The dates below will help you  plan  for
any optional cash investments during 1998.

Date Investment Must Be          Investment
Received By Transfer Agent       Dates

April 8                          April 15
May 8                            May 15
June 8                           June 15
July 8                           July 15
August 7                         August 14
September 8                      September 15
October 7                        October 15
November 6                       November 13
December 8                       December 15


Equity Research

Equity   research   reports   are  independently   prepared   and
distributed  by the following firms: A. G. Edwards & Sons,  Inc.;
Edward  Jones; First Dallas Securities; Merill Lynch; and  Tucker
Anthony Incorporated.

Investment Information

Colonial  Gas  Company  is a corporate  member  of  the  National
Association of Investors Corporation (NAIC). The Company is  also
a participant in NAIC's Low Cost Investment Plan.

SHAREHOLDER INFORMATION

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 1997
and 1996, and the quarterly dividends paid per share.

                           Sales Prices        Dividends
                           High    Low       Paid per Share

1997                    __________________________________

The Year              	 $30-1/16  $19-1/4       $1.330
4th Quarter               30-1/16   23-11/16       .335
3rd Quarter               25-1/4    20-1/2         .335
2nd Quarter               22-3/4    19-1/4         .335
1st Quarter               24        20             .325


1996                    __________________________________

The Year                 $24-1/4   $20           $1.295
4th Quarter               24        21-1/4         .325
3rd Quarter               24-1/4    20-1/4         .325
2nd Quarter               24-1/4    20             .325
1st Quarter               24        20-1/4         .320



Shareholders and Record Holders
At December 31, 1997, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,111
shareholders of record.
                                 

            [END OF EXHIBIT 13a TO COLONIAL GAS COMPANY
              10-K FOR YEAR ENDED DECEMBER 31, 1997]