[EXHIBIT 13a TO COLONIAL GAS COMPANY
FOR 10-K FOR YEAR ENDED DECEMBER 31, 1995]

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands Except Per Share Amounts) Year Ended December 31,
                                         1995      1994      1993

Operating Revenues                   $164,649  $166,259  $166,261
Cost of gas sold                       83,631    87,458    90,915
  Operating Margin                     81,018    78,801    75,346
Operating Expenses:
  Operations                           31,309    33,004    32,957
  Maintenance                           4,401     5,074     4,726
  Depreciation and amortization        10,225     9,235     6,831
  Local property taxes                  3,020     2,740     2,496
  Other taxes                           2,130     2,182     2,055
  Restructuring charge                      -     3,185         -
   Total Operating Expenses            51,085    55,420    49,065
Income Taxes:
  Federal income tax                    6,912     4,806     6,111
  State franchise tax                   1,447     1,058     1,280
   Total Income Taxes                   8,359     5,864     7,391
Utility Operating Income               21,574    17,517    18,890
Other Operating Income (Expense):
  Truck transportation revenues         7,576    12,066     7,558
  Truck transportation expenses, 
  including income taxes and interest  (6,972)  (10,579)   (7,163)
   Truck Transportation Net Income        604     1,487       395
  Other, net of income taxes               (8)     (151)     (186)
   Total Other Operating Income           596     1,336       209
Non-Operating Income, Net of Income       864       565     1,064
   Taxes  
Income Before Interest and Debt        23,034    19,418    20,163
   Expense
Interest and Debt Expense               9,270     8,409     8,141
Net Income                            $13,764   $11,009   $12,022

Average Common Shares Outstanding       8,294     8,119     7,931

Income per Average Common Share         $1.66     $1.36     $1.52

Dividends Paid per Common Share        $1.275    $1.255    $1.235


The accompanying notes are an integral part of these statements.

[END OF CONSOLIDATED STATEMENTS OF INCOME]

CONSOLIDATED BALANCE SHEETS

Assets                                        December 31,
(In Thousands)                               1995     1994
Utility Property:
At original cost                          $308,191  $287,158
  Accumulated depreciation                 (72,636)  (65,473)
     Net Utility Property                  235,555   221,685
Non-Utility Property - Net                   5,036     3,479
     Net Property                          240,591   225,164

Capital Leases - Net                         2,253     2,948

Current Assets:
Cash and cash equivalents                    7,541     9,026
Accounts receivable                         19,069    13,846
  Allowance for doubtful accounts           (2,205)   (1,670)
Accrued utility revenues                     8,924     6,148
Unbilled gas costs                           9,688    12,178
Fuel inventory - at average cost            10,516    12,959
Materials and supplies - at average	     3,132     3,537
   cost
Prepayments and other current assets         4,337     9,544

     Total Current Assets                   61,002    65,568

Deferred Charges and Other Assets:
Unrecovered deferred income taxes           10,562    11,471
Unrecovered demand side management costs     4,977     3,120
Unrecovered environmental costs incurred     4,761     4,577
Unrecovered environmental costs accrued      2,300     3,800
Unrecovered pension costs                    3,917     2,607
Unrecovered transition costs accrued         3,600     4,700
Excess cost of investments over net assets   2,798     2,798
   acquired
Other                                        5,660     4,595
     Total Deferred Charges and Other       38,575    37,668
   Assets
Total Assets                              $342,421  $331,348

CONSOLIDATED BALANCE SHEETS

Capitalization and Liabilities                 December 31,
(In Thousands)                               1995      1994
Capitalization:
Common Equity:
Common Stock                               $27,863   $27,397
Premium on Common Stock                     51,447    49,211
Retained earnings                           25,760    22,567
     Total Common Equity                   105,070    99,175
Long-Term Debt                              75,418    77,923
     Total Capitalization                  180,488   177,098
Capital Lease Obligations                    1,359     2,237

Current Liabilities:
Current maturities of long-term debt         6,141     8,449
Current capital lease obligations              894       712
Notes payable                               61,835    49,500
Gas inventory purchase obligations          12,340    13,860
Accounts payable                            12,150     9,635
Accrued interest                             1,065     1,085
Pipeline refunds due customers               1,310     2,289
Current deferred income taxes                  314     2,139
Other current liabilities                    5,617     3,713
     Total Current Liabilities             101,666    91,382

Deferred Credits and Reserves:
Deferred income taxes - Funded              32,299    29,373
Deferred income taxes - Unfunded            10,562    11,471
Deferred income taxes - Due customers          112       378
Accrued environmental costs                  2,300     3,800
Accrued transition costs                     3,600     4,700
Unamortized investment tax credits           3,940     4,215
Pension reserve                              4,929     5,510
Other deferred credits and reserves          1,166     1,184
     Total Deferred Credits and Reserves    58,908    60,631
Total Capitalization and Liabilities      $342,421  $331,348


The accompanying notes are an integral part of these statements.

[END OF CONSOLIDATED BALANCE SHEETS]

CONSOLIDATED STATEMENTS OF CASH FLOWS
                                         Year Ended December 31,
(In Thousands)                            1995     1994     1993
Cash Flows From Operating Activities:
Net Income                             $13,764  $11,009  $12,022
Adjustments to reconcile net income 
  to net cash:
  Depreciation and amortization         11,211   10,150    7,703
  Deferred income taxes                  1,159    3,555    2,139
  Amortization of investment tax credits  (275)    (234)    (255)
  Provision for uncollectible accounts   1,829    1,803    2,102
  Other, net                               973      811      190
                                        28,661   27,094   23,901
Changes in current assets and 
   liabilities:
  Accounts receivable                   (6,517)     495      773
  Accrued utility revenues              (2,776)   1,022   (1,678)
  Unbilled gas costs                     2,490    4,581    2,122
  Fuel inventory                         2,443      758     (285)
  Materials and supplies                   405      275       56
  Prepayments and other current assets   5,207   (3,290)   2,055
  Accounts payable                       2,515   (2,526)    (382)
  Accrued interest                         (20)      68       (7)
  Pipeline refunds due customers          (979)     213      620
  Accrued pipeline charges                   -     (305)    (606)
  Current deferred income taxes         (1,825)     (73)  (2,111)
  Other current liabilities              1,904      (13)     933
Net Cash Provided by Operating          31,508   28,299   25,391
  Activities
Cash Flows From Investing Activities:
 Utility capital expenditures          (24,096) (28,195) (25,703)
 Non-utility capital expenditures       (1,974)    (876)    (453)
 Sale of non-utility assets                  -        -      586
 Change in deferred accounts            (2,077)    (716)    (354)
Net Cash Used in Investing Activities  (28,147) (29,787) (25,924)
Cash Flows From Financing Activities:
 Dividends paid on Common Stock        (10,571) (10,187)  (9,793)
 Issuance of Common Stock                2,702    4,070    4,283
 Issuance of long-term debt, net of 
   issuance costs                       19,685      741        -
 Retirement of long-term debt,         (27,477)  (5,119)  (1,500)
   including premiums
 Change in notes payable                12,335   16,900    8,100
 Change in gas inventory purchase       (1,520)  (1,373)     492
  obligations
Net Cash (Used in) Provided by          (4,846)   5,032    1,582
  Financing Activities
Net (Decrease) Increase in Cash and     (1,485)   3,544    1,049
  Cash Equivalents
Cash and Cash Equivalents at Beginning   9,026    5,482    4,433
  of Year
Cash and Cash Equivalents at End       $ 7,541  $ 9,026 $  5,482
  of Year
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized   $ 9,867  $ 9,283 $  8,891
Income and state franchise taxes       $ 3,444  $ 7,282 $  4,939

The accompanying notes are an integral part of these statements.

[END OF CONSOLIDATED STATEMENTS OF CASH FLOWS]

CONSOLIDATED STATEMENTS OF COMMON EQUITY

                                           Year ended December 31,
(In Thousands Except Per Share Amounts)      1995    1994    1993

Common Stock
  $3.33 par value; authorized 15,000 shares;
   outstanding, 8,367 in 1995, 8,227 in 1994,
   and 8,030 in 1993
  Beginning of year                       $27,397 $26,739 $26,122
   Issuance of Common Stock through
     Dividend Reinvestment and Common
      Stock Purchase Plan and
      Employee savings plan (140 shares
      in 1995, 197 shares in 1994 and 186
      shares in 1993)                         466     658     617

  End of year                             $27,863 $27,397 $26,739

Premium on Common Stock
  Beginning of year                       $49,211 $45,799 $42,133
   Issuance of Common Stock through
     Dividend Reinvestment and Common
      Stock Purchase Plan and
      Employee savings plan                 2,236   3,412   3,666

  End of year                             $51,447 $49,211 $45,799

Retained Earnings
  Beginning of year                       $22,567 $21,745 $19,516
   Net income                              13,764  11,009  12,022
   Cash dividends on Common Stock ($1.275
       a share in 1995, $1.255 a share in
      1994 and $1.235 a share in 1993)    (10,571)(10,187) (9,793)

  End of year                             $25,760 $22,567 $21,745

      Total Common Equity                $105,070 $99,175 $94,283


The accompanying notes are an integral part of these statements.

[END OF CONSOLIDATED STATEMENTS OF COMMON EQUITY]

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  141,000  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 Public Utilities
(DPU)  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  $568,000,
$294,000 and $227,000 in 1995, 1994 and 1993, 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  DPU.  The   composite
depreciation  rate which was approximately 2.91%  through  October
31,  1993, was increased to approximately 3.77% effective  with  a
rate  increase  as approved by the DPU on November  1,  1993.  The
composite  depreciation rate 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 $8,924,000 and
$6,148,000,  as  reported in the Consolidated  Balance  Sheets  at
December 31, 1995 and 1994, 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
DPU. In September 1995, the Company received approval from the DPU
to  recover financial incentives and lost margins associated  with
the  residential DSM programs. Based on this approval, the Company
recorded  $900,000  of  lost  margins and  $220,000  of  financial
incentives  as revenue in 1995. No lost margins or incentives  for
the commercial DSM programs have been recorded to date.

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 DPU.

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  DPU,  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 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 and  additional
contributions  to  fund  the  unqualified  individual   retirement
agreements.

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 $81,559,000 and $86,372,000 as of December 31, 1995
and  1994,  respectively.  The fair value  of  long-term  debt  was
$89,724,000  and  $88,425,000 as of December  31,  1995  and  1994,
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.

Reclassifications  -  Reclassifications are made  periodically  to
previously  issued financial statements to conform to the  current
year presentation.

New  Accounting Standard - In March 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards
No.  121  "Accounting for the Impairment of Long-Lived Assets  and
Long-Lived Assets to be Disposed Of", which will be effective  for
the Company's fiscal year ending December 31, 1996. 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  Company
intends to adopt this statement prospectively. The impact of  this
standard  is  not  expected  to have  a  material  impact  on  the
Company's financial condition or results of operations.



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 DPU, the Company did
not  record deferred income taxes but rather "flowed through"  tax
benefits  to utility customers. At December 31, 1995, the  Company
has  a  liability of $10,562,000 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, 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.
      The  Company  has  a liability (Deferred Income  Taxes-  Due
Customers)  of  $112,000  at December 31, 1995,  representing  the
amount  of  pre-July  1,  1987 deferred  income  taxes  that  were
recorded  in  excess of the Federal statutory income tax  rate  of
34%.  This  liability is being returned to utility customers  over
the  remaining  book life of utility property. This  liability  is
also charged for any Federal income taxes at rates above 34%.
Federal income tax expense is comprised of the following
components:
                                      Year Ended December 31,
(In Thousands)                        1995     1994     1993
Charged (credited) to operations:
Current                             $6,455   $2,157   $5,191
Deferred:
  Unbilled gas costs                (1,523)    (106)  (1,753)
  Accelerated depreciation           2,005    2,167    2,157
  Demand side management costs         (32)   1,115        -
  Pension                              (38)    (840)     141
  Recovery of unfunded deferred taxes  398      398      556
  Debt expense                         848      (21)     (20)
  Transition costs                    (871)     (55)       -
  Miscellaneous                        (57)     221       84
Amortization of investment tax        (273)    (230)    (245)
  credits
     Total                           6,912    4,806    6,111
Charged to other income                477    1,014      578
Total Federal income tax expense    $7,389   $5,820   $6,689
        

The  effective  Federal income tax rate and the  reasons  for  the
difference  from  the statutory Federal income  tax  rate  are  as
follows:
                                      1995     1994     1993
Statutory Federal income tax rate      35%      35%      35%
Increases (reductions) in taxes 
     resulting from:
   Amortization of investment tax      (1)      (1)      (1)
     credit
   Recovery of unfunded deferred taxes  2        2        3
   Miscellaneous items                 (1)      (1)      (1)
Effective Federal income tax rate      35%      35%      36%

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

                                       December 31,
(In Thousands)                        1995        1994
Construction contributions         $ 1,060    $  1,117
Other                                1,468         943
   Total deferred tax assets         2,528       2,060
Accelerated depreciation           (36,949)    (34,698)
Cost of removal                     (2,554)     (2,364)
Unbilled gas costs                    (315)     (3,184)
Environmental response costs        (1,865)     (1,839)
Demand side management costs        (1,764)     (1,803)
Other                               (2,256)     (1,155)
   Total deferred tax liabilities  (45,703)    (45,043)
Total deferred taxes              $(43,175)   $(42,983)


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:  Retained Earnings

The  Company's ability to pay dividends on its Common  Stock  from
retained  earnings  is  restricted  by  the  first  mortgage  bond
indenture  and  by  the  bank  line  of  credit.  Under  the  most
restrictive   covenant,  approximately  $23,943,000  of   retained
earnings  was  available to pay dividends on Common  Stock  as  of
December 31, 1995.



Note E:  Long-Term Debt

The composition of long-term debt is as follows:
                                           December 31,
   (In Thousands)                         1995     1994
First mortgage bonds:
  14.00%  Series CC due 1999           $     -  $   500
   8.86%  Series CD due 2001             6,000    7,000
   9.40%  Series CE due 1997            10,000   15,000
  10.25%  Series CF due 2004                 -   18,182
   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       10,000        -
   6.45%  Series MTA-2   due 2025       10,000        -

        Total                           81,000   85,682
Note payable                               559      690
Less: Long-term debt due within         (6,141)  (8,449)
  one year

Total long-term debt                   $75,418  $77,923

The  aggregate amount of maturities and sinking fund  requirements
for  the  years  1996, 1997, 1998, 1999, and 2000 are  $6,141,000,
$6,152,000, $1,164,000, $21,102,000, and $1,000,000, respectively.
  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.
  In September 1995, with the approval of the DPU, the Company
established a medium term note (MTN) program which permits the
issuance of up to $75 million of MTN's as bonds under its
indenture. In October 1995, the Company issued $10 million of 30-
year bonds with an average effective interest rate of 6.85% (6.44%
during the first ten years and 7.38% in the next twenty years). In
December 1995, the Company issued $10 million of 30-year bonds with
an average effective interest rate of 6.45% (6.08% during the first
ten years and 6.90% in the next twenty years). Both issues of bonds
can be redeemed by the holder within a 30 day period at the end of
ten years. It is anticipated that the remaining bonds under the MTN
program will be issued in several series over the next two years.
  On December 29, 1995, the Company redeemed prior to maturity the
$16,364,000 of Series CF, 10.25%, first mortgage bonds.

Note F:  Short-Term Debt

In  July  1994, the Company established a three-year bank line  of
credit  of $75 million with a consortium of four 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  four
alternative  rates:  prime  rate,  certificate  of  deposit  rate,
eurodollar rate (LIBOR), and a competitive bid option. At December
31,  1995, the credit available under the bank line of credit  was
$825,000. The weighted average interest rates for short-term  debt
were 6.03% and 6.25% at December 31, 1995 and 1994, 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  DPU  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 1995,  1994  and
1993  approximately $529,000, $504,000 and $390,000, respectively,
of financing costs were incurred by the trust.



Note G:  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
$7,291,000  and  $7,230,000  at  December  31,  1995   and   1994,
respectively.  Accumulated  amortization  on  assets  held   under
capital leases amounted to approximately $5,038,000 and $4,282,000
at December 31, 1995 and 1994, 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  1995,  1994  and  1993
approximated  $1,429,000, $2,049,000 and $1,808,000, respectively.
At  December  31,  1995,  the future minimum  payments  (including
interest)  under the Company's lease agreements are:  $894,000  in
1996;  $742,000  in  1997;  $605,000 in 1998;  $296,000  in  1999;
$254,000 in 2000; and $355,000 thereafter.

Note H:  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 $459,000, $387,000  and  $418,000  for
1995, 1994 and 1993, 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)                       1995      1994     1993

Benefits earned during the period  $  836   $ 1,195  $ 1,031
Interest cost on projected          3,279     2,803    2,690
  benefit obligation
Actual return on plan assets       (5,515)       77   (2,656)
Net amortization and deferral       2,757    (2,657)     325
Net periodic pension cost          $1,357    $1,418   $1,390

Assumptions used in actuarial calculations were as follows:

                                    Year Ended December 31,
                                   1995      1994     1993

Weighted average discount rate     7.50%     8.50%    7.25%
Future compensation increases      4.00%     5.00%    5.00%
Expected long-term rate of return  9.00%     9.00%    9.00%
  on assets


The funded status of the plans at December 31, 1995 and 1994 is as
follows:
                                  1995                     1994
                          Assets   Accumulated        Assets  Accumulated
                          Exceed      Benefits        Exceed     Benefits
                     Accumulated        Exceed   Accumulated       Exceed
(In Thousands)          Benefits        Assets      Benefits       Assets
                                                      
Projected benefit                                     
obligations:
  Vested               $(28,993)    $(10,388)    $(21,897)     $(8,544)
  Nonvested                (628)        (869)      (2,988)        (563)
Accumulated             (29,621)     (11,257)     (24,885)      (9,107)
Due to recognition of                                          
future salary increases  (4,173)         (88)      (4,664)         (42)
    
          Total         (33,794)     (11,345)     (29,549)      (9,149)
Plan assets at fair      31,168        6,420       27,715        5,259
value
Projected benefit        (2,626)      (4,925)     (1,834)       (3,890)
     obligation         
     in excess of
     plan assets
Unrecognized net loss     1,758        1,232        (227)          513
   (gain)
Unrecognized              1,572        1,247       2,059         1,430
   transition amount
Unrecognized prior          347        1,493         448           706
   service cost
Additional liability          -       (3,885)          -        (2,607)
   accrued
Prepaid (accrued)        $1,051      $(4,838)    $   446       $(3,848) 
   pension costs

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.

Additional benefits upon retirement were given to 47 employees who
accepted  the  voluntary early retirement  program  in  1994.  The
additional  loss  of $2,537,000 as a result of  this  program  was
recorded as a restructuring charge in the fourth quarter of 1994.

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. As permitted by SFAS  106,
the  Company will record the transition obligation over a  twenty-
year period. The Company's cost under this plan for 1995, 1994 and
1993   was  $672,000,  $694,000  and  $817,000,  respectively.   A
regulatory asset of $431,000 was recorded in 1993, leaving  a  net
expense  of $386,000. This regulatory asset represents 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 DPU's approval of  the  Company's  new
rates.  Currently,  the  DPU  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 Company  is
currently  funding an amount each year equal to  the  maximum  tax
deductible amount.
      The  following  table  sets forth the plan's  funded  status
reconciled with the amounts recognized in the Company's  financial
statements at December 31, 1995 and 1994:

(In Thousands)                       1995       1994
                                               
Accumulated postretirement                   
       benefit obligation:
     Retirees                     $(3,816)   $(2,416)
     Fully eligible active plan    (1,047)    (1,457)
       participants
     Other active plan             (1,275)    (1,782)
       participants
                                   (6,138)    (5,655)
Plan assets at fair value           4,102      3,135
Accumulated postretirement         (2,036)    (2,520)          
     benefit obligation          
     in excess of plan assets
Unrecognized net (gain) from       (1,310)    (1,016)       
     past experience                              
     different from that assumed  
     and from changes in assumptions
Unrecognized transition obligation  4,584      4,854
Prepaid postretirement benefit     $1,238     $1,318
     cost

Net  periodic  postretirement benefit cost included the  following
components:

                                Year Ended December 31,
(In Thousands)                  1995      1994      1993
                                                    
Service cost - benefits         $145      $202      $268                    
    attributable to service     
    during the period
Interest cost on accumulated     505       455       478                    
    postretirement               
    benefit obligation
Actual return on plan assets    (639)      143      (202)
Net amortization and deferral    661      (106)      273
Net periodic postretirement     $672      $694      $817
    benefit cost

     For measurement purposes, a 7% (4.5% for dental costs) annual
rate  of  increase in the per capita cost of covered  health  care
benefits  was assumed for 1996; the rate of increase  for  medical
costs  was assumed to decrease gradually from 7% to 4.5%  in  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,
1995 by $706,000 and the aggregate of the service and the interest
cost  components of net periodic postretirement benefit  cost  for
the year then ended by $84,000.
      The  weighted average discount rate used in determining  the
accumulated  postretirement benefit obligation was 7.5%  and  8.5%
for  1995 and 1994, 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.


Postemployment  Benefits  -  During  1994,  the  Company   adopted
Statement  of  Financial Accounting Standards No. 112  "Employer's
Accounting for Postemployment Benefits" (SFAS 112). This statement
requires  accrual  accounting for benefits to former  or  inactive
employees after employment but before retirement. The adoption  of
SFAS  112  did  not  have a significant effect  on  the  Company's
results of operations.

Note I:  Other Commitments

Long-Term Obligations - The Company has contracts, which expire at
various  dates through the year 2012, for the acquisition  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 transition cost liabilities are estimated to range  from
$11,600,000  to  $16,400,000,  of  which  the  Company  has   paid
$8,000,000  through December 31, 1995. The Company  is  recovering
these  costs from its customers, as approved by the DPU in October
1994.  As  of December 31, 1995, the Company has recorded  on  the
balance  sheet  a  long-term  liability  of  $3,600,000  ("Accrued
Transition  Costs") and, based upon rate recovery, has recorded  a
regulatory  asset  of  $3,600,000 ("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 J:  Contingencies
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 DPU  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, 1995,  the
Company  had  incurred environmental response costs of $10,418,000
of  which $2,904,000 was for the former gas manufacturing site and
$7,514,000 for the related disposal sites. The Company expects  to
continue incurring costs arising from these environmental matters.
  As of December 31, 1995, the Company has recorded on the balance
sheet  a  long-term liability of $2,300,000 representing estimated
future  response  costs  for these sites based  on  the  Company's
preferred  methods of remediation, of which $1,700,000 relates  to
the  gas  manufacturing site. Based upon the DPU  order  approving
rate  recovery of environmental response costs, a regulatory asset
of $2,300,000 has been recorded on the balance sheet ("Unrecovered
Environmental Costs Accrued"). 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.
  As of December 31, 1995, the Company had settled claims relating
to  these  matters  with all liability insurers  and  other  known
potentially responsible parties (PRP). In accordance with the  DPU
order  referred  to  above, half the costs  incurred  in  pursuing
insurers  and other PRP are recovered from the ratepayers  through
the  CGAC  and half are initially borne by the Company. Also,  per
this order, any insurance and other proceeds are applied first  to
the  Company's costs of pursuing recovery from insurers and  other
PRP, with the remainder divided equally between the ratepayers and
shareholders.
   The  table  below summarizes the environmental  response  costs
incurred  and  insurance and other proceeds received  relating  to
these environmental response costs:

(In Thousands)         Response Costs        Insurance and Other Proceeds
                     Recovered    Period                       Recorded as
                       from      of Rate     Returned to      Non-Operating
Year       Incurred  Customers   Recovery     Customers      Income Net of
                                                                   Taxes
                                             
1988         $   853   $   732     1990-1997         -               -
1989           4,031     3,455     1990-1997         -               -
1990             639       457     1991-1998         -               -
1991             374       213     1992-1999   $   851         $   525
1992             617       264     1993-2000     1,121             673
1993           1,226       350     1994-2001       469             290
1994           1,321       189     1995-2002       122              75
1995           1,357         -     1996-2003         -               -

Total        $10,418    $5,660                  $2,563          $1,563


Note K:  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
1995
December 31       $56,625   $10,283    $8,530   $1.02       $.320
September 30       14,911    (2,251)   (3,932)   (.47)       .320
June 30            22,760      (925)   (3,283)   (.40)       .320
March 31           70,353    14,467    12,449    1.51        .315
1994
December 31       $48,077    $6,741    $4,782  $  .58       $.315
September 30       13,026    (3,132)   (4,834)   (.59)       .315
June 30            19,073    (1,849)   (3,338)   (.41)       .315
March 31           86,083    15,757    14,399    1.79        .310

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 L:  Restructuring Charge

In   the   fourth  quarter  of  1994,  the  Company   recorded   a
restructuring charge of $3,185,000 ($1,965,000 after-tax  or  $.24
per  share).  This amount includes $2,537,000 for the  cost  of  a
voluntary  early  retirement program  which  was  accepted  by  47
employees  and  $648,000  for costs  accrued  by  the  Company  in
connection with the closure of two retail appliance stores.

[END OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS]

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, 1995  and
1994,  and  the  related consolidated statements of  income,  cash
flows, and common equity for each of the three years in the period
ended  December  31,  1995.  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, 1995 and 1994, and the consolidated results of  their
operations and their consolidated cash flows for each of the three
years  in  the period ended December 31, 1995, in conformity  with
generally accepted accounting principles.



GRANT THORNTON LLP


Boston, Massachusetts
January 17, 1996


[END OF REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS]

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  $13,764,000
($1.66), $11,009,000 ($1.36) and $12,022,000 ($1.52) for the three
years  ended  December  31, 1995, 1994,  and  1993,  respectively.
Before a restructuring charge after-tax of $1,965,000 or $.24  per
share,  1994 net income and income per average common  share  were
$12,974,000 ($1.60).
    Net   income  was  favorably  impacted  by  colder-than-normal
temperatures  in  1995,  1994  and  1993,  although  at  declining
percentages over the periods. This is summarized as follows:

                                          1995    1994   1993
Percent colder than normal                 2.7%    5.3%   6.7%

Percent (warmer) colder than prior year   (2.5)%  (1.3)%  3.3%

Other items which had an impact on net income are discussed in the
following sections.
   Dividends paid per common share were $1.275 in 1995, $1.255  in
1994  and  $1.235 in 1993. The Company has paid dividends  for  59
consecutive years, and has increased dividends each year  for  the
past 16 years.


Operating Revenues
Operating revenues were $164,649,000 in 1995, $166,259,000 in 1994
and  $166,261,000 in 1993. Operating revenues are impacted by  the
volumes  of  gas sold and transported, changes in  base  rates  as
approved  by  the  Massachusetts Department  of  Public  Utilities
(DPU),  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 sales  customers
increased by 13,395 over the last three years from 127,964 in 1992
to  141,359 in 1995, an increase of 10.5%, which has added to firm
sales  volume. The chart below summarizes volumes of gas sold  and
transported and number of firm sales customers:

                                        1995    1994    1993
(In MMcf)
Gas sold
   Firm                               18,560  18,716  18,935
   Non-Firm                            1,148     729   1,030
Gas transported
   Firm                                2,537   6,090   4,163
   Non-Firm                            3,224   4,185   4,026

         Total gas sold and 
            transported (In MMcf)     25,469  29,720  28,154

Firm Sales Customers                 141,359 136,636 132,187


   Operating revenues decreased $1,610,000, or 1.0%, from 1994  to
1995. This decrease resulted primarily from weather that was  2.5%
warmer  than  the  prior year (although 2.7% colder  than  normal)
partially offset by a growing customer base and additional revenue
of  $1,120,000 resulting from regulatory approval to recover  lost
margins  and  financial incentives associated with  the  Company's
residential conservation programs.
   Operating  revenues were unchanged from 1993 to  1994.  Utility
revenues  were positively impacted during 1994 by a 3.4%  customer
growth and a 4.9% rate increase which became effective in November
1993.  Weather, although 5.3% colder than normal, was 1.3%  warmer
than 1993.

Cost of Gas Sold
Average cost of gas sold per Mcf was $4.22 in 1995, $4.48 in  1994
and  $4.53  in  1993.  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)                                1995    1994    1993
Gas purchased
  Pipeline                             14,659  14,392  14,983
  Underground storage                   3,270   3,112   3,501
  LNG/Other                             2,426   2,390   1,832

     Total gas purchased               20,355  19,894  20,316

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  $31,309,000  in  1995,  a  decrease   of
$1,695,000  or  5.1%,  from  1994, and  $33,004,000  in  1994,  an
increase  of  $47,000, or 0.1%, from 1993. In  1994,  the  Company
conducted  a  self-examination to reduce its cost  structure.  The
decrease  in  1995 was primarily due to less payroll  and  related
benefits  as  a result of the early retirement program  and  other
cost  saving initiatives. The Company has budgeted no increase  in
operations and maintenance costs in 1996.
   Maintenance expense decreased $673,000, or 13.3%, in 1995  from
1994  and  increased  $348,000, or 7.4%, in 1994  from  1993.  The
decrease in 1995 was primarily due to cost controls resulting from
the  Company's self-examination in 1994. The increase in 1994  was
primarily  due  to increased labor resulting from  colder  weather
during the first quarter.
    Depreciation  and  amortization  expense  increased  10.7%  or
$990,000 in 1995 and 35.2% or $2,404,000 in 1994. The increase  in
1995  was due to an increase in utility property. The increase  in
1994  was primarily due to the increased depreciation rates  as  a
result of the Company's 1993 rate order and an increase in utility
property.
   Local property and other taxes increased 4.6% in 1995 from 1994
and 8.2% in 1994 from 1993. The increase in 1995 was due to higher
property taxes and additional property subject to property subject
to property taxes. The increase in 1994 was due to higher property
and  payroll  taxes, and additional property subject  to  property
taxes.
   A  restructuring charge of $3,185,000 ($1,965,000 after-tax  or
$.24  per  share) was recorded during the fourth quarter of  1994.
This  amount includes $2,537,000 for the cost of a voluntary early
retirement program which was accepted by 47 employees and $648,000
for costs accrued by the Company in connection with the closure of
two retail appliance stores.

Income Taxes
Total Federal income and state franchise taxes increased 42.5%  or
$2,495,000 in 1995 as a result of a higher level of income.  Total
Federal  income  and  state  franchise taxes  decreased  20.7%  or
$1,527,000 in 1994 as a result of less income.

Other Operating Income (Expense)
Other operating income (expense), net of income taxes was $596,000
in  1995, $1,336,000 in 1994 and $209,000 in 1993. 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.  As
discussed   previously,  the  Company's  retail  appliance   sales
operation was discontinued as of December 31, 1994.
   Transgas' 1994 financial results were driven by extremely  cold
weather in the first quarter of 1994 which generated a significant
increase  in  demand  for  the truck transportation  of  liquefied
natural  gas (LNG) and propane throughout the first three quarters
of  1994.  This  accounts  for the sharp increase  in  1994  other
operating income.
   Factors  affecting  the future financial  results  of  Transgas
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 $864,000  in  1995,
$565,000  in  1994  and  $1,064,000 in 1993. Non-operating  income
includes  interest income and miscellaneous other income. Included
in  non-operating  income  for 1994 and 1993  were  recoveries  of
$75,000  and  $290,000, respectively, resulting  from  settlements
reached  with  insurers and other potentially responsible  parties
relating  to  environmental  response  costs  as  described  under
"Environmental Matters". Also included in non-operating income for
1993  is  an insurance recovery of $509,000 relating to a line  of
business that was discontinued in 1979.

Interest and Debt Expense
Interest  and debt expense increased 10.2% and 3.3%  in  1995  and
1994,  respectively.  The increase in 1995 was  due  to  increased
levels  of  short-term debt and higher short-term  interest  rates
partially offset by a decrease in interest on long-term debt.  The
increase  in  1994 was due to increased levels of short-term  debt
and  higher  short-term  interest  rates  partially  offset  by  a
decrease in interest on long-term debt due to paydowns in 1993.

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 DPU.  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
Environmental  response costs, transition costs  and  demand  side
management (DSM) program costs are recovered through the CGAC,  as
approved  by  the DPU. 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  FERC approved pipeline charges  resulting  from
Order   636.  In  addition  to  full  recovery  of  the  installed
conservation  measures,  the Company is  allowed  to  recover  the
margins  lost  as  a  result  of the DSM  programs  and  financial
incentives  based  on  the  attainment of  performance  goals.  In
September  1995,  the Company received approval from  the  DPU  to
recover lost margins and financial incentives associated with  the
residential  DSM  programs. Based on this  approval,  the  Company
recorded  as  operating  revenues $900,000  of  lost  margins  and
$220,000  of financial incentives in 1995. The Company anticipates
recording as operating revenues approximately $1 million  of  lost
margins  and  incentives  associated  with  the  residential   and
commercial DSM programs in 1996.
   In  1993, the Company applied for what was only its second base
rate increase request since 1984. Effective November 1, 1993,  the
Company  received  DPU  approval of a  settlement  agreement  that
called  for  a  base rate increase designed to produce  additional
revenues  of  $6.7 million or 4.9% annually. In addition  to  this
rate  increase,  the  DPU  approved  a  proposal  to  expand   the
eligibility  criteria for Colonial's discount rate for  low-income
residential  heating customers and allowed the Company  to  retain
10%  of  the  revenues  generated  from  releasing  the  Company's
interstate pipeline transportation capacity to third parties above
an  initial threshold of $2,500,000. In 1995, the Company received
$2,818,000  of capacity release revenue, $2,786,000 of  which  was
credited  back to firm customers and $32,000 of which was retained
by the Company.
   The table below summarizes the Company's last three requests to
increase base revenue:


                       Increase Requested           Increase Approved
 Date Effective    Amount          Percentage   Amount        Percentage
                                                          
November 1, 1984   $ 4.30 million    3.73%      $2.8 million      2.4%
                 
November 1, 1990   $12.80 million    9.86%      $7.9 million      5.6%
               
November 1, 1993   $10.75 million    7.87%      $6.7 million      4.9%
               

   In  1993,  Colonial began unbundling its firm sales service  to
commercial  and industrial customers by offering a  tariffed  firm
transportation-only service. Pursuant to this service, a  customer
procures  its own gas supply and contracts with Colonial for  firm
transportation service through Colonial's distribution system.  As
of  December  31, 1995, 11 customers had opted for  tariffed  firm
transportation service, representing less than 2% of the Company's
annual firm load.
  Two 1994 DPU industry-wide proceedings may result in the further
unbundling  and  deregulation of the Company's  business.  One  of
those  proceedings addresses whether and how the traditional cost-
of-service/rate-of-return method of regulating  gas  and  electric
utilities   might  be  replaced  with  some  type  of  alternative
"incentive" method. In a ruling issued in February 1995,  the  DPU
indicated  that  it  has  the  authority  to  implement  incentive
regulation  and would be receptive to various types of  proposals.
The Company continues to analyze specific incentive regulation and
unbundling options which it could propose to the DPU as a means of
benefiting  its  customers and shareholders. The other  proceeding
addresses  whether interruptible transportation and  interruptible
sales service on local distribution company (LDC) systems, and the
release  of  interstate  pipeline  capacity  by  LDCs,  should  be
structured or priced differently. The Company expects DPU  rulings
containing general guidelines on these matters in 1996.

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 DPU  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, 1995,  the
Company  had incurred environmental response costs of $10,418,000,
of  which $2,904,000 was for the former gas manufacturing site and
$7,514,000 for the related disposal sites. The Company expects  to
continue incurring costs arising from these environmental matters.
As of December 31, 1995, the Company had recovered $5,660,000 from
customers  and $1,563,000 from liability insurers and other  known
potentially responsible parties.
  As of December 31, 1995, the Company has recorded on the balance
sheet  a  long-term liability of $2,300,000 and, based  upon  rate
recovery,  has  recorded  a corresponding  regulatory  asset.  The
amount represents estimated future response costs for these  sites
based  on the Company's preferred methods of remediation, of which
$1,700,000   relates  to  the  gas  manufacturing   site.   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

In  March  1995, the Financial Accounting Standards  Board  issued
Statement  of  Financial Accounting Standards No. 121  "Accounting
for  the Impairment of Long-Lived Assets and Long-Lived Assets  to
be  Disposed Of", which will be effective for the Company's fiscal
year ending December 31, 1996. 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 Company intends to adopt  this
statement  prospectively.  The impact  of  this  standard  is  not
expected  to  have  a  material impact on the Company's  financial
condition or results operations.

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. As permitted by SFAS 106, the Company  will
record  the  transition obligation over a twenty-year period.  The
Company's  cost  under  this plan for  1995,  1994  and  1993  was
$672,000, $694,000 and $817,000, respectively. A regulatory  asset
of  $431,000  was  recorded  in 1993, leaving  a  net  expense  of
$386,000.   This  regulatory  asset  represents  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 DPU's approval of the Company's new  rates.
Currently  the DPU allows Massachusetts utilities to  recover  the
tax deductible portion of these postretirement benefits.

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
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
$24,096,000 in 1995, $28,195,000 in 1994 and $25,703,000 in  1993.
The   Company's   long-range  plan  calls   for   annual   utility
expenditures,  of  which over 40% is budgeted  for  new  business,
averaging $27,000,000 over the next five years as follows:

                                                              
(In Thousands)           1996     1997      1998     1999     2000
                                                          
Distribution          $20,700  $22,700   $22,300  $26,500  $24,800
Production              1,400    1,000     1,000      700      750
Information Systems     4,300    1,000       700      500      140
Automated Meter         1,100    1,100    $1,100    1,100       30
Reading
General                   300      700       300      400      380

     Total Capital    $27,800  $26,500   $25,400  $29,200  $26,100
     Expenditures

Financing Activities
In September 1995, with the approval of the DPU, the Company
established a medium term note (MTN) program which permits the
issuance of up to $75 million of MTN's as bonds under its
indenture. In October 1995, the Company issued $10 million of 30-
year bonds with an average effective interest rate of 6.85% (6.44%
during the first ten years and 7.38% in the next twenty years). In
December 1995, the Company issued $10 million of 30-year bonds with
an average effective interest rate of 6.45% (6.08% during the first
ten years and 6.90% in the next twenty years). Both issues of bonds
can be redeemed by the holder within a 30 day period at the end of
ten years. In February 1996, the Company issued $10 million of 30-
year bonds with an interest rate of 6.94%. It is anticipated that
the remaining bonds under the MTN program will be issued in several
series over the next two years.
     On December 29, 1995, the Company redeemed prior to maturity the
$16,364,000 of Series CF, 10.25%, first mortgage bonds.
     The  Company has a $75 million credit facility which allows it  to
meet  its  seasonal  working capital needs. The  present  facility
expires in June 1997. 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  four
alternative rates.
  The Company has raised permanent capital during the last three
years as follows:
(In Thousands)                            1995     1994        1993
Common Stock Under Dividend Reinvestment
  and Common Stock Purchase Plan and
  Employee Savings Plan                 $2,702   $4,070      $4,283
Long-Term Debt
  Note Payable                               -   $  741           -
  MTA-1, 6.85%, due 2025 *             $10,000        -           -
  MTA-2, 6.45%, due 2025 *             $10,000        -           -

* Subject to redemption in 2005 at the option of the holder

   The  equity  and  debt  components  of  the  Company's  capital
structure at the end of the year is shown in the table below:

                                        1995    1994   1993
Equity                                   58%     56%    52%
Long-Term Debt                           42%     44%    48%

   As  of April 1995, the quarterly dividend paid on the Company's
Common  Stock  was  increased to $.32 per share or  an  annualized
dividend rate of $1.28 per share.

[END   OF  MANAGEMENT'S  DISCUSSION  AND  ANALYSIS  OF  FINANCIAL
CONDITION AND RESULTS OF OPERATIONS]


SELECTED FINANCIAL DATA

(For the Years Ending December 31)
(In Thousands Except Per Share Amounts)

                             1995      1994     1993      1992      1991 

Balance Sheet Data:
Assets:   
Utility property-net	 $235,555  $221,685  $202,713  $183,815  $162,736
Non-Utility property-net    5,036     3,479     3,235     4,039     4,767
Capital leases-net	    2,253     2,948     3,914  	  4,366     4,557
Current assets             61,002    65,568    67,668    71,763    53,472
Deferred charges and       38,575    37,668    34,588    38,939    38,789
   other assets
    Total                $342,421  $331,348  $312,118  $302,922  $264,321
Capitalization and 
   Liabilities:
Capitalization:
Common equity	         $105,070  $ 99,175  $ 94,283  $ 87,771  $ 82,221 
Long-term debt             75,418    77,923    87,432    90,750    50,410
   Total Capital-
     ization              180,488   177,098   181,715   178,521   132,631
Capital lease               1,359     2,237     3,149     3,591     3,838
   obligations	           
Current liabilities       101,666    91,382    73,413    64,567    73,993
Deferred credits and       58,908    60,631    53,841    56,243    53,859
   reserves  
  
     Total               $342,421  $331,348  $312,118  $302,922  $264,321

Income Statement Data:
Operating revenues       $164,649  $166,259  $166,261  $145,054  $137,719
Cost of gas sold          (83,631)  (87,458)  (90,915)  (75,143)  (73,288)
Operating margin           81,018    78,801    75,346    69,911    64,431
Operating expenses        (59,444)  (61,284)  (56,456)  (52,760)  (48,009)
   (including income 
    taxes)
Utility operating          21,574    17,517    18,890    17,151    16,422
   income
Other income-               1,460     1,901     1,273       958        36
   net of income taxes
Interest and               (9,270)   (8,409)   (8,141)   (7,466)   (8,141)
   debt expense
Accounting change               -         -         -         -         -
Preferred stock                 -         -         -         -         -
   dividends
Net income applicable     $13,764   $11,009   $12,022   $10,643    $8,317
   to common stock


Capitalization Ratios:
Common equity                 58%       56%       52%       49%       62%
Long-term debt                42%       44%       48%       51%       38%

Common Stock Data:
Average shares              8,294     8,119     7,931     7,728     7,529
   outstanding
Income per share            $1.66     $1.36(a)  $1.52     $1.38     $1.10
Dividends paid per share:
   Common Stock            $1.275    $1.255    $1.235    $1.213    $1.193
   Class A Common Stock         -         -         -         -         -
   Per weighted average    $1.275    $1.255    $1.235    $1.213    $1.193
     common share
Dividend payout rate          77%       92%       81%       88%      108%
Book value per share       $12.56    $12.05    $11.74    $11.19    $10.78
Dividends as a percent        10%       10%       11%       11%       11%
   of book value
Market price per share     $20.25    $19.25    $22.50    $21.25    $17.50
Market price as a            161%      160%      192%      190%      162%
   percent of book value
Return on average           13.5%     11.4%     13.2%     12.5%     10.2%
   common equity

(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.


SELECTED FINANCIAL DATA - Continued
(For the Years Ending December 31)
(In Thousands Except Per Share Amount)

  
                             1990      1989     1988       1987      1986

Balance Sheet Data:
Assets:                 
Utility property-net     $151,480  $139,764 $131,450   $121,034  $111,214
Non-Utility property-net    5,076     3,893    2,793      3,167     3,665
Capital leases-net          4,962     5,853    6,679      6,563     9,201
Current assets             46,393    56,753   50,414     36,757    37,234
Deferred charges and       29,925    27,464   21,050     20,376     4,235
   other assets
    Total                $237,836  $233,727 $212,386   $187,897  $165,549
Capitalization and 
   Liabilities:
Capitalization:
Common equity            $ 80,109  $ 66,568 $ 63,027   $ 58,238  $ 54,569
Long-term debt             64,604    69,512   55,102     58,572    47,528
   Total Capital-         144,713   136,080  118,129    116,810   102,097
     ization
Capital lease               4,233     4,714    5,457      5,556     8,258
   obligations
Current liabilities        47,729    54,590   53,375     34,781    41,151
Deferred credits and       41,161    38,343   35,425     30,750    14,043
   reserves
     Total               $237,836  $233,727 $212,386   $187,897  $165,549

Income Statement Data:
Operating revenues       $134,298  $139,892 $115,851   $117,947  $126,099
Cost of gas sold          (78,930)  (82,189) (63,401)   (65,093)  (75,157)
Operating margin           55,368    57,703   52,450     52,854    50,942
Operating expenses        (42,853)  (41,525) (38,844)   (38,343)  (37,938)
   (including income
    taxes)
Utility operating          12,515    16,178   13,606     14,511    13,004
   income
Other income-               1,625       956    1,046        233       383
   net of income taxes
Interest and               (8,445)   (8,217)  (7,369)    (6,740)   (5,861)
   debt expense
Accounting change               -         -    2,014          -         -
Preferred stock                 -         -        -          -      (312)
   dividends
Net income applicable     $ 5,695   $ 8,917  $ 9,297    $ 8,004   $ 7,214
   to common stock


Capitalization Ratios:
Common equity                 55%       49%      53%        50%       53%
Long-term debt                45%       51%      47%        50%       47%

Common Stock Data:
Average shares              6,963     6,200    6,065      5,948     5,588
   outstanding
Income per share            $0.82     $1.44    $1.53(b)   $1.35     $1.29
Dividends paid per share:
   Common Stock            $1.167    $1.140   $1.113     $1.087    $1.060
   Class A Common Stock         -         -   $ .800     $ .760    $ .720
   Per weighted average    $1.167    $1.140   $1.013     $ .987    $ .960
     common share
Dividend payout rate         142%       79%      66%        73%       74%
Book value per share       $10.75    $10.62   $10.27     $ 9.69    $ 9.25
Dividends as a percent        11%       11%      11%        11%       11%
   of book value
Market price per share     $15.00    $14.67   $13.00     $11.83    $14.33
Market price as a            139%      138%     127%       122%      155%
   percent of book value
Return on average            7.8%     13.8%    15.3%      14.2%     14.3%
   common equity
  

(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.


[END OF SELECTED FINANCIAL DATA]


SHAREHOLDER INFORMATION

Corporate Headquarters
Colonial Gas Company
40 Market Street
P.O. Box 3064
Lowell, MA 01853-3064
(508) 458-3171
FAX: (508) 459-2314

Stock Listing
The  Company's  Common Stock trades on the  Nasdaq  Stock  Market
under  the  symbol: CGES. Stock trading activity is  reported  in
financial  publications  under  the  abbreviation  of  ColGas  or
ClnGas.

Annual Meeting
The Annual Meeting of Stockholders will be held on April 17, 1996
at  10:00 A.M. at The First National Bank of Boston, 100  Federal
Street, Boston, Massachusetts.

Annual Report - Form 10-K
A  copy of the Company's 1995 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.

Transfer Agent
The First National Bank of Boston
c/o Boston EquiServe, L.P.
P.O. Box 644
Mail Stop: 45-02-64
Boston, MA  02102-0644
(800) 736-3001
(617) 575-3100

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

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

Dividends
The Company has paid dividends on Common Stock for 59 consecutive
years  and  has  increased dividends each year for  the  past  16
years.  Common Stock dividends are payable when declared  by  the
Board of Directors.

Anticipated Record Date       Anticipated Payment Date
March 1, 1996                 March 15, 1996
May 31, 1996                  June 14, 1996
August 30, 1996               September 13, 1996
November 29, 1996             December 13, 1996

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 1996.

Date Investment Must Be        Investment
Received By Transfer Agent     Dates
April 8                        April 15
May 8                          May 15
June 7                         June 14
July 8                         July 15
August 8                       August 15
September 6                    September 13
October 7                      October 15
November 8                     November 15
December 6                     December 13

SHAREHOLDER INFORMATION

Market Prices and Dividends
The following table reflects the high and low sales prices as reported
by the Nasdaq Stock Market, for shares of the Company's Common Stock
for 1995 and 1994, and the quarterly dividends paid per share.

                      Sales Prices  Dividends
                  High    Low     Paid per Share


1995           

The Year        $21.50   $18.00    $1.275
4th Quarter      21.50    19.50      .320
3rd Quarter      20.75    18.75      .320
2nd Quarter      21.25    18.00      .320
1st Quarter      21.25    18.25      .315


1994          

The Year        $23.75   $18.25    $1.255
4th Quarter      21.75    18.25      .315
3rd Quarter      22.00    20.50      .315
2nd Quarter      21.75    18.50      .315
1st Quarter      23.75    18.75      .310


_________________________________________________________________

Shareholders and Record Holders
At December 31, 1995, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,592
shareholders of record.

Market Makers
Colonial currently has the following market makers: A. G. Edwards
&  Sons,  Inc.; Edward D. Jones & Co.; First Albany  Corporation;
Herzog,  Heine,  Geduld,  Inc.; S. J. Wolfe  &  Co.;  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.

[END OF SHAREHOLDER INFORMATION]

[END OF EXHIBIT 13a TO COLONIAL GAS COMPANY
FOR 10-K FOR YEAR ENDED DECEMBER 31, 1995]