[EXHIBIT 13a TO COLONIAL GAS COMPANY 10-K FOR YEAR ENDED DECEMBER 31, 1996]

                 CONSOLIDATED STATEMENTS OF INCOME

(In Thousands Except Per Share Amounts) Year Ended December 31,
                                      1996        1995        1994

Operating Revenues                  $170,929    $164,649    $166,259
Cost of gas sold                      87,188      83,631      87,458
Operating Margin                      83,741      81,018      78,801

Operating Expenses:
Operations                            31,383      31,309      33,004
Maintenance                            4,476       4,401       5,074
Depreciation and amortization         11,228      10,225       9,235
Local property taxes                   3,189       3,020       2,740
Other taxes                            2,183       2,130       2,182
Restructuring charge                     -           -         3,185
Total Operating Expenses              52,459      51,085      55,420

Income Taxes:
Federal income tax                     7,001       6,912       4,806
State franchise tax                    2,087       1,447       1,058
Total Income Taxes                     9,088       8,359       5,864
Utility Operating Income              22,194      21,574      17,517

Other Operating Income (Expense):
Truck transportation revenues         11,031       7,576      12,066
Truck transportation expenses,including
  income taxes and interest           (9,005)     (6,972)    (10,579)
Truck Transportation Net Income        2,026         604       1,487
Other, net of income taxes               210          (8)       (151)
Total Other Operating Income           2,236         596       1,336
Non-Operating Income, 
  Net of Income Taxes                    757         864         565
Income Before Interest 
  and Debt Expense 	              25,187      23,034      19,418
Interest and Debt Expense              8,709       9,270       8,409
Net Income                           $16,478     $13,764     $11,009

Average Common Shares Outstanding      8,432       8,294       8,119
Income per Average Common Share        $1.95       $1.66       $1.36

The accompanying notes are an integral part of these statements.

                    CONSOLIDATED BALANCE SHEETS

Assets                                        December 31,
(In Thousands)                       1996     	             1995

Utility Property:
At original cost                    $333,319                $308,191
Accumulated depreciation             (82,336)                (72,636)
Net Utility Property                 250,983                 235,555
Non-Utility Property - Net             5,925                   5,036
Net Property                         256,908                 240,591
Capital Leases - Net                   1,811                   2,253

Current Assets:
Cash and cash equivalents              3,541                   7,541
Accounts receivable                   17,719                  19,069
Allowance for doubtful accounts       (2,715)                 (2,205)
Accrued utility revenues               6,333                   8,924
Unbilled gas costs                    19,238                   9,688
Fuel inventory - at average cost      11,958                  10,516
Materials and supplies 
  -at average cost                     2,891                   3,132
Prepayments and other current assets   8,593                   4,337

Total Current Assets                  67,558                  61,002

Deferred Charges and Other Assets:
Unrecovered deferred income taxes      9,774                  10,562
Unrecovered demand 
  side management costs                7,075                   4,977
Unrecovered environmental 
  costs incurred                       4,011                   4,761
Unrecovered environmental 
  costs accrued 		       1,183                   2,300
Unrecovered pension costs              3,135                   3,917
Unrecovered transition costs accrued   4,500                   3,600
Excess cost of investments over 
  net assets acquired                  2,798                   2,798
Other                                  5,659                   5,660

Total Deferred 
Charges and Other Assets              38,135                  38,575
Total Assets                        $364,412                $342,421

                    CONSOLIDATED BALANCE SHEETS

Capitalization and Liabilities            December 31,
(In Thousands)                       1996                    1995

Capitalization:
Common Equity:
Common Stock                         $28,366                  $27,863
Premium on Common Stock               54,221                   51,447
Retained earnings                     31,319                   25,760
Total Common Equity                  113,906                  105,070
Long-Term Debt                        95,266                   75,418
Total Capitalization                 209,172                  180,488
Capital Lease Obligations                930                    1,359

Current Liabilities:
Current maturities of long-term debt   5,152                    6,141
Current capital lease obligations        881                      894
Notes payable                         50,400                   61,835
Gas inventory purchase obligations    13,039                   12,340
Accounts payable                      14,544                   12,150
Accrued interest                       1,815                    1,065
Current deferred income taxes          5,090                      314
Other current liabilities              3,248                    6,927
Total Current Liabilities             94,169                  101,666

Deferred Credits and Reserves:
Deferred income taxes - Funded        35,886                   32,299
Deferred income taxes - Unfunded       9,774                   10,562
Accrued environmental costs            1,183                    2,300
Accrued transition costs               4,500                    3,600
Unamortized investment tax credits     3,672                    3,940
Pension reserve                        4,174                    4,929
Other deferred credits and reserves      952                    1,278

Total Deferred Credits and Reserves   60,141                   58,908
Total Capitalization and 
  Liabilities                       $364,412                 $342,421

The accompanying notes are an integral part of these statements.

               CONSOLIDATED STATEMENTS OF CASH FLOWS

                                         Year Ended December 31,
(In Thousands)                        1996        1995        1994
Cash Flows From Operating Activities:

Net Income                           $16,478     $13,764     $11,009

Adjustments to reconcile net income to net cash:
Depreciation and amortization         12,361      11,211      10,150
Deferred income taxes                  7,968       1,159       3,555
Amortization of investment 
  tax credits                           (268)       (275)       (234)
Provision for uncollectible 
  accounts		               2,146       1,829       1,803
Other, net                               171         973         811
Total adjustments                     38,856      28,661      27,094

Changes in current assets and liabilities:
Accounts receivable                     (286)     (6,517)        495
Accrued utility revenues               2,591      (2,776)      1,022
Unbilled gas costs                    (9,550)      2,490       4,581
Fuel inventory                        (1,442)      2,443         758
Materials and supplies                   241         405         275
Prepayments and other 
  current assets                      (4,256)      5,207      (3,290)
Accounts payable                       2,394       2,515      (2,526)
Accrued interest                         750         (20)         68
Pipeline refunds due customes         (2,077)       (979)        213
Accrued pipeline charges                 -            -         (305)
Other current liabilities             (1,602)         79         (86)
Net Cash Provided by 
  operating activity                  25,619      31,508      28,299

Cash Flows From Investing Activities:
Utility capital expenditures         (26,875)    (24,096)    (28,195)
Non-utility capital expenditures      (1,367)     (1,974)       (876)
Change in deferred accounts           (1,502)     (2,077)       (716)
Net Cash Used in 
  Investing Activities               (29,744)    (28,147)    (29,787)

Cash Flows From Financing Activities:
Dividends paid on Common Stock       (10,919)    (10,571)    (10,187)
Issuance of Common Stock               3,277       2,702       4,070
Issuance of long-term debt, 
  net of issuance costs               29,787	  19,685         741
Retirement of long-term debt, 
  including premiums	             (11,284)    (27,477)     (5,119)
Change in notes payable              (11,435)     12,335      16,900
Change in gas inventory 
  purchase obligations                   699      (1,520)     (1,373)
Net Cash Provided by (Used in) 
  Financing Activities         	         125      (4,846)      5,032
Net (Decrease) Increase in Cash 
  and Cash Equivalents                (4,000)     (1,485)      3,544
Cash and Cash Equivalents 
  at Beginning of Year                 7,541       9,026       5,482
Cash and Cash Equivalents 
  at End of Year                      $3,541      $7,541      $9,026

Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized  $9,149      $9,867      $9,283
Income and state franchise taxes      $8,489      $3,444      $7,282

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)   
  	                              1996        1995        1994

Common Stock
$3.33 par value; authorized 15,000 shares;
outstanding, 8,518 in 1996, 8,367 in 1995,
and 8,227 in 1994

Beginning of year                    $27,863     $27,397     $26,739
  Issuance of Common Stock through
  Dividend Reinvestment and Common
  Stock Purchase Plan and
  Employee savings plan (151 shares
  in 1996, 140 shares in 1995 
  and 197 shares in 1994)                503         466         658

End of year                          $28,366     $27,863     $27,397

Premium on Common Stock
  Beginning of year                  $51,447     $49,211     $45,799

Issuance of Common Stock through
  Dividend Reinvestment and Common
  Stock Purchase Plan and
  Employee savings plan                2,774       2,236       3,412

End of year                          $54,221     $51,447     $49,211

Retained Earnings
Beginning of year                    $25,760     $22,567     $21,745
Net income                            16,478      13,764      11,009
Cash dividends on Common 
  Stock ($1.295 a share in 1996, 
  $1.275 a share in 1995 and 
  $1.255 a share in 1994)	     (10,919)    (10,571)    (10,187)

End of year                          $31,319     $25,760     $22,567

Total Common Equity                 $113,906    $105,070     $99,175

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  145,000  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  $437,000,
$568,000, and $294,000 in 1996, 1995 and 1994, 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   is   approximately  3.79%.   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 $6,333,000 and
$8,924,000,  as  reported in the Consolidated  Balance  Sheets  at
December 31, 1996 and 1995, 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. Under methodologies approved in 1995 for its residential  DSM
programs  and in 1996 for its commercial and industrial  programs,
the  Company  recorded as revenue $1,034,000 of lost  margins  and
$142,000  of  financial incentives in 1996 and  $900,000  of  lost
margins and $220,000 of financial incentives in 1995.

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 for the qualified plan 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  $100,418,000 and $81,559,000 as of  December  31,
1996  and 1995, respectively. The fair value of long-term debt  was
$102,016,000  and  $89,724,000 as of December 31,  1996  and  1995,
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 DPU, the Company did not
record deferred income taxes but rather "flowed through" tax
benefits to utility customers. At December 31, 1996, the Company has
a liability of $9,774,000 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)                        1996        1995        1994
Charged (credited) to operations:
Current                                $1,104     $6,455       $2,157
Deferred:
Unbilled gas costs                      2,929     (1,523)        (106)
Accelerated depreciation                2,202      2,005        2,167
Demand side management costs              747        (32)       1,115
Pension                                   449        (38)        (840)
Recovery of unfunded deferred taxes       398        398          398
Debt expense                              (53)       848          (21)
Transition costs                           (1)      (871)         (55)
Environmental                            (246)        22          137
Miscellaneous                            (260)       (79)          84
Amortization of investment 
  tax credits                            (268)      (273)        (230)
Total                                   7,001      6,912        4,806 
Charged to other income                 1,599        477        1,014
Total Federal income tax expense       $8,600     $7,389       $5,820

The  effective  Federal income tax rate and the  reasons  for  the
difference  from  the statutory Federal income  tax  rate  are  as
follows:
                                      1996        1995        1994

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                    (2)         (1)         (1)
Effective Federal 
  income tax rate                      34%         35%         35%

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

                                             December 31,
(In Thousands)                 	     1996                    1995

Construction contributions           $974  	            $1,060
Other                                 335                    1,468
Total deferred tax assets           1,309                    2,528
Accelerated depreciation          (39,580)                 (36,949)
Cost of removal                    (2,792)                  (2,554)
Unbilled gas costs                 (3,990)                    (315)
Environmental response costs       (1,571)                  (1,865)
Demand side management costs       (2,659)                  (1,764)
Other                              (1,467)                  (2,256)
Total deferred tax liabilities    (52,059)                 (45,703)
Total deferred taxes             $(50,750)                $(43,175)

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:
                                             December 31,
   (In Thousands)                    1996                    1995
First mortgage bonds:
8.86%  Series CD  due 2001        $ -                       $6,000
9.40%  Series CE  due 1997          5,000                   10,000
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     10,000                   10,000
6.45%  Series MTA-2   due 2025     10,000                   10,000
6.94%  Series MTA-3   due 2026     10,000                     -
6.20%  Series MTA-4   due 1998     10,000                     -
6.88%  Series MTA-5   due 2008     10,000                     -
Total                             100,000                   81,000
Note payable                          418                      559

Less: Long-term debt due 
within one year                    (5,152)                  (6,141)

Total long-term debt              $95,266                  $75,418

     The aggregate amount of maturities for the years 1997, 1998, 1999,
2000 and 2001 are $5,152,000, $10,164,000, $20,102,000, $0 and $0,
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 1995, the Company issued $10 million of 30-year bonds
(MTA-1) with an average effective interest rate of 6.85% (6.44%
during the first ten years and 7.38% in the next twenty years) and
$10 million of 30-year bonds (MTA-2) 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. During
1996, the Company issued three separate medium term notes totalling
$30 million at various rates and terms. It is anticipated that the
remaining bonds under the MTN program will be issued in 1997.

     In June 1996, the Company redeemed prior to maturity $5 million
of Series CD, 8.86%, first mortgage bonds.

Note E:  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,  1996, the credit available under the bank line of credit  was
$11,561,000.  The weighted average interest rates  for  short-term
debt  were  5.87%  and  6.03%  at  December  31,  1996  and  1995,
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 1996,  1995  and
1994  approximately $500,000, $662,000 and $504,000, 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
$7,685,000  and  $7,291,000  at  December  31,  1996   and   1995,
respectively.  Accumulated  amortization  on  assets  held   under
capital leases amounted to approximately $5,874,000 and $5,038,000
at December 31, 1996 and 1995, 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  1996, 1995 and  1994
approximated  $1,493,000, $1,429,000 and $2,049,000, respectively.
At  December  31,  1996,  the future minimum  payments  (including
interest)  under the Company's lease agreements are:  $881,000  in
1997;  $737,000  in  1998;  $420,000 in 1999;  $300,000  in  2000;
$255,000 in 2001; and $100,000 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 $570,000, $459,000  and  $387,000  for
1996, 1995 and 1994 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)                         1996        1995        1994

Benefits earned during the period      $1,036       $836      $1,195
Interest cost on projected 
  benefit obligation                    3,267      3,279       2,803
Actual return on plan assets           (4,710)    (5,515)         77
Net amortization and deferral           1,882      2,757      (2,657)
Net periodic pension cost              $1,475     $1,357      $1,418

Assumptions used in actuarial calculations were as follows:

					  Year Ended December 31,
                                       1996       1995         1994

Weighted average discount rate         7.75%      7.50%        8.50%
Future compensation increases          4.00%      4.00%        5.00%
Expected long-term rate of 
  return on assets                     9.00%      9.00%        9.00%

The funded status of the plans at December 31, 1996 and 1995 is as
follows:
                            1996                       1995
                     Assets  Accumulated        Assets   Accumulated
                     Exceed     Benefits        Exceed      Benefits   
                Accumulated       Exceed   Accumulated        Exceed
(In Thousands)     Benefits       Assets      Benefits        Assets          
                                                                             
Projected benefit                                     
obligations:

Vested           $(28,612)      $(10,381)      $(28,993)    $(10,388)
Nonvested            (703)          (956)          (628)        (869)
Accumulated       (29,315)       (11,337)       (29,621)     (11,257)

Due to recognition 
of future salary 
  increases        (4,248)          (116)        (4,173)         (88)

  Total           (33,563)       (11,453)       (33,794)     (11,345)

Plan assets at 
  fair value       33,743          7,715         31,168        6,420
  Projected benefit 
  obligation:                                              

Less than (in         180          (3,738)       (2,626)      (4,925)
  excess of)           
  plan assets

Unrecognized net     (457)            188         1,758        1,232
  (gain) loss

Unrecognized        1,398           2,020         1,572        1,247
  transition amount

Unrecognized prior    487           1,064           347        1,493
  service cost

Additional liability   -           (3,157)           -        (3,885)  
  accrued                  

Prepaid (accrued)  $1,608         $(3,623)       $1,051      $(4,838)
  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  cost  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.  The Company amortizes  the
transition  obligation  over a twenty-year period.  The  Company's
cost  under  this  plan  for 1996, 1995  and  1994  was  $502,000,
$672,000 and $694,000 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  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  following  table  sets forth the plan's  funded  status
reconciled with the amounts recognized in the Company's  financial
statements at December 31, 1996 and 1995:

(In Thousands)                       1996                    1995
                                             
Accumulated postretirement                   
benefit obligation:
Retirees                         $(3,957)                 $(3,816)
Fully eligible active plan                    
  participants                    (1,033)                  (1,047)
Other active plan               
  participants                    (1,239)                  (1,275)
   Total                          (6,229)                  (6,138)
Plan assets at fair value          4,563                    4,102

Accumulated postretirement  
  benefit obligation                 
  in excess of plan assets:       (1,666)                  (2,036)

Unrecognized net (gain) from      (1,339)                  (1,310)    
  past experience different from 
  that assumed and from changes 
  in assumptions

Unrecognized transition            4,315                    4,584
  obligation

Prepaid postretirement benefit    $1,310                   $1,238
  cost

Net periodic postretirement benefit cost included the following
components:

                                         Year Ended December 31,
(In Thousands)                         1996       1995         1994
                                                    
Service cost - benefits                             
  attributable to service              $137       $145         $202
  during the period
Interest cost on accumulated            461        505          455
  postretirement                  
  benefit obligation
Actual return on plan assets           (507)      (639)         143
Net amortization and deferral           410        661         (106)
Net periodic postretirement            $501       $672         $694
  benefit cost

      For  measurement  purposes, a 6.5% (4.5% for  dental  costs)
annual  rate of increase in the per capita cost of covered  health
care  benefits  was  assumed for 1997; the rate  of  increase  for
medical costs was assumed to decrease gradually from 6.5% 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,  1996  by  $755,000 and the aggregate of the service  and  the
interest  cost  components of net periodic postretirement  benefit
cost for the year then ended by $71,000.

     The  weighted average discount rate used in determining  the
accumulated postretirement benefit obligation was 7.75%, 7.5%  and
8.5% for 1996, 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.

Note H:  Other Commitments

Long-Term Obligations - The Company has contracts, which expire at
various  dates through the year 2013, 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 additional transition cost liabilities are estimated  to
range  from  $4,500,000 to $6,500,000. The Company  is  recovering
these  costs from its customers, as approved by the DPU in October
1994.  As  of December 31, 1996, the Company has recorded  on  the
balance  sheet  a  long-term  liability  of  $4,500,000  ("Accrued
Transition  Costs") and, based upon rate recovery, has recorded  a
regulatory  asset  of  $4,500,000 ("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

     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, 1996,  the
Company  had  incurred environmental response costs of $11,156,000
of which $7,148,000 has been recovered from customers to date. The
Company  expects  to continue incurring costs arising  from  these
environmental matters.

     As of December 31, 1996, the Company has recorded on the balance
sheet  a  long-term liability of $1,183,000 and, based  upon  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
1996

December 31      $53,869    $9,236     $7,035    $.83       $.325
September 30      15,245    (2,566)    (3,580)   (.42)       .325
June 30           24,237      (689)    (2,205)   (.26)       .325
March 31          77,578    16,213     15,228    1.82        .320
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

     In the opinion of management, the quarterly financial data includes
all adjustments, consisting only of normal recurring accruals,
necessary for a fair presentation of such information.  The Company
typically reports profits during the first and fourth quarters of
each year while incurring losses during the second and third
quarters. This is due to significantly higher natural gas sales
during the colder months to satisfy customers' heating needs.

Note K:  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.

Note L:  Subsequent Event

     In January 1997, the Company executed definitive agreements with
Cabot LNG Corporation (Cabot) to (1) sell a 50% interest in Transgas
for $7,000,000 as part of a joint venture and (2) form a separate
joint venture owned 50/50 which will lease Colonial's LNG storage
tank and related equipment. These joint ventures combine the LNG
trucking and storage capabilities of Colonial with the marketing and
storage capabilities of Cabot, and are expected to expand the
overall utilization of LNG. Completion of the sale of the Transgas
interest and implementation of the LNG storage joint venture is
subject to certain regulatory approvals. Colonial will recognize a
one-time gain, net of taxes, of approximately $.35 per share at the
time of the sale, expected to occur in the first half of 1997.

        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, 1996 and
1995, and the related consolidated statements of income, cash flows,
and common equity for each of the three years in the period ended
December 31, 1996.  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 financialstatements referred to above present
fairly, in all material respects, the consolidated financial
position of Colonial Gas Company and subsidiaries as of December 31,
1996 and 1995, and the consolidated results of their operations and
their consolidated cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally
accepted accounting principles.

GRANT THORNTON LLP
Boston, Massachusetts
January 13, 1997

                       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 Officer   Executive Vice President-
					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 $16,478,000
($1.95), $13,764,000 ($1.66) and $11,009,000 ($1.36) for the three
years ended December 31, 1996, 1995, and 1994, respectively.  Before
a restructuring charge of $1,965,000 after-tax 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 20-year average
temperatures in 1996, 1995 and 1994.  This is summarized as follows:

                                       1996       1995         1994

Percent colder than 
  20-year average                      3.0%       2.3%         5.0%

Percent colder (warmer) 
  than prior year                      0.7%      (2.5)%       (1.3)%

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

     Dividends paid per common share were $1.295 in 1996, $1.275 in 1995
and $1.255 in 1994. The Company has paid dividends for 60
consecutive years, and has increased dividends each year for the
past 17 years.

Operating Revenues

     Operating revenues were $170,929,000 in 1996, $164,649,000 in 1995
and $166,259,000 in 1994. 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 13,235 over the last three years from 132,187 in December 1993 to
145,422 in December 1996, an increase of 10%, which has added to
firm sales volume. The chart below summarizes volumes of gas sold
and transported and number of firm sales customers:

                                       1996       1995         1994
(In MMcf)

Gas sold
Firm                                  19,563      18,560      18,716
Non-Firm                                 648       1,148         729
Gas transported
Firm                                   3,918       2,537       6,090
Non-Firm                               2,671       3,224       4,185
Total gas sold and transported        26,800      25,469      29,720
  (In MMcf)
Firm Sales Customers                 145,422     141,359     136,636


     Operating revenues increased $6,280,000, or 3.8% from 1995 to 1996.
This increase resulted from weather that was 0.7% colder than last
year and customer growth of 2.9%.

     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 2.3% colder than the 20-year average)
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.

Cost of Gas Sold

     Average cost of gas sold per Mcf was $4.29 in 1996, $4.22 in 1995
and $4.48 in 1994.  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)                             1996        1995        1994

Gas purchased 
Pipeline                              15,115      14,659      14,392
Underground storage                    3,346       3,270       3,112
LNG/Other                              2,596       2,426       2,390
Total gas purchased                   21,057      20,355      19,894

     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 $31,383,000 in 1996, an increase of $74,000
or 0.2%, from 1995, and $31,309,000 in 1995, a decrease of
$1,695,000, or 5.1%, from 1994. In 1996, the Company was able to
maintain operations expense at prior years level. The decrease in
1995 was primarily due to less payroll and related benefits as a
result of the early retirement program and cost saving initiatives
resulting from the Company's self-examination in 1994.  Maintenance
expense increased $75,000, or 1.7%, in 1996 from 1995 and decreased
$673,000, or 13.3%, in 1995 from 1994.  The decrease in 1995 was
primarily due to cost saving initiatives.

     Depreciation and amortization expense increased 9.8% or $1,003,000
in 1996 and 10.7% or $990,000 in 1995. The increases in 1996 and
1995 were due to an increase in utility property.

     Local property and other taxes increased 4.3% in 1996 from 1995 and
4.6% in 1995 from 1994. The increases in 1996 and 1995 were due to
higher property 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 8.7% or
$729,000 in 1996 as a result of a higher level of income.  Total
Federal income and state franchise taxes increased 42.5% or
$2,495,000 in 1995 as a result of more income.

Other Operating Income (Expense)

     Other operating income (expense), net of income taxes was $2,236,000
in 1996, $596,000 in 1995 and $1,336,000 in 1994. 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' 1996 financial results were driven by a 68% increase in
liquefied natural gas (LNG) hauls leading to a $3,455,000 increase
in trucking revenue and a $1,422,000 increase in truck
transportation net income.  This increase in demand of truck
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.

     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.

     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.

     As discussed in "LNG Joint Ventures", the Company has agreed to sell
a 50% interest in Transgas. Effective upon such sale, the Company
will be recognizing 50% of the net income of Transgas on an equity
basis.

Non-Operating Income

     Non-operating income, net of income taxes, was $757,000 in 1996,
$864,000 in 1995 and $565,000 in 1994.  Non-operating income
includes interest income and miscellaneous other income.

Interest and Debt Expense

     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. Interest and debt expense
increased 10.2% in 1995 from 1994. 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.

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, 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.
In 1996, the Company recorded as operating revenues $1,034,000 of
lost margins and $142,000 of financial incentives associated with
the residential and commercial DSM programs and in 1995, recorded as
operating revenues $900,000 of lost margins and $220,000 of
financial incentives.

     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 DPU approved a base rate increase designed to produce
additional revenues of $6.7 million or 4.9% annually, effective
November 1, 1993.

     The Company's goal is to postpone the filing of a request for its
next base rate increase until at least the year 2000 through
cost-cutting and other measures, such as the LNG joint venture with
Cabot LNG Corporation described below, while maintaining an adequate
return to shareholders. Under a 1995 industry-wide ruling of the
DPU, 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.  The Company has reviewed alternative 
incentive-based pricing methods but has not yet determined
what method of regulation will be of greatest benefit to its 
customers and shareholders. 

     During 1996, the DPU ordered all Massachusetts gas companies to
offer only "unbundled"  gas service to interruptible and special
contract customers, as a means of promoting greater competition at
the city-gate. 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 had previously offered both
bundled and unbundled service to interruptible and special contract
customers.

     Since 1993, the Company also has been offering unbundled service 
as an alternative to its firm commercial and industrial customers.
As of December 31, 1996, 19 customers had opted for the firm
transportation service, representing less than 2% of the Company's
annual firm load.  The Company is analyzing methods for making
unbundled service viable for the greater number of firm customers,
and anticipates DPU rulings containing additional unbundling
guidelines in 1997.

     In its 1996 order, the DPU continued to allow Massachusetts gas
companies to price interruptible services at negotiated rates based
on the value of that service to the customer. Additionally,
Massachusetts gas companies will now be permitted to retain 25% of
the net margins earned on interruptible sales, interruptible
transportation and capacity release transactions, to the extent
those margins exceed thresholds based on previous activity.  The
Company had previously been allowed to retain 10% of capacity
release revenues above an initial threshold of $2,500,000 under its
1993 base rate proceeding. The amounts retained by the Company from
interruptible sales, interruptible transportation and capacity
release transactions in 1996, 1995 and 1994 totaled $0, $81,000 and
$32,000 respectively. All other revenues from these transactions
flow back to firm sales customers through the CGAC.

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, 1996, the Company had
incurred environmental response costs of $11,156,000 of which
$7,148,000 has been recovered from customers to date. The Company
expects to continue incurring costs arising from these environmental
matters.

     As of December 31, 1996, the Company has recorded on the balance
sheet a long-term liability of $1,183,000 and, based upon 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.

                  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 $26,875,000 in
1996, $24,096,000 in 1995 and $28,195,000 in 1994.  The Company's
long-range plan calls for annual utility expenditures, of which over
50% is budgeted for new business, averaging $28,000,000 over the
next five years as follows:

                                                              
(In Thousands)          1997      1998     1999     2000     2001
                                                          
Distribution          $22,900   $22,500  $23,100  $23,800  $24,700
Production              3,200       200      100      400      300
Information Systems     7,400     4,100      400      400      400
Automated Meter         1,100     1,100    1,200      300      300
Reading
General                                                           
                          200       300      300      300      300
Total Capital         $34,800   $28,200  $25,100  $25,200  $26,000
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 1995, the Company issued $10 million of 30-year bonds (MTA-1)
with an average effective interest rate of 6.85% (6.44% during the
first ten years and 7.38% in the next twenty years) and $10 million
of 30-year bonds (MTA-2) 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. During 1996, the Company
issued three separate medium term notes totaling $30 million at
various rates and terms. It is anticipated that the remaining bonds
under the MTN program will be issued in 1997.

     In June 1996, the Company redeemed prior to maturity the $5 million
of Series CD, 8.86%, first mortgage bonds.

     The aggregate amount of maturities for the years 1997, 1998, 1999,
2000 and 2001 are $5,152,000, $10,164,000, $20,102,000, $0 and $0,
respectively.

     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 expects to make new short-term
credit arrangements prior to the expiration of the credit facility.

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

(In Thousands)                        1996        1995        1994
Common Stock Under 
  Dividend Reinvestment
  and Common Stock Purchase 
  Plan and
  Employee Savings Plan               $3,277      $2,702      $4,070
Note Payable                            -            -          $741
Medium term notes under the 
  first mortgage indenture           $30,000     $20,000         -

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

                                      1996        1995        1994

Equity                                54%          58%        56%
Long-Term Debt                        46%          42%        44%

   As  of April 1996, the quarterly dividend paid on the Company's
Common  Stock  was increased to $.325 per share or  an  annualized
dividend rate of $1.30 per share.

LNG Joint Ventures

     In January 1997, the Company executed definitive agreements with
Cabot LNG Corporation (Cabot) to (1) sell a 50% interest in Transgas
for $7,000,000 as part of a joint venture and (2) form a separate
joint venture owned 50/50 which will lease Colonial's LNG storage
tank and related equipment. These joint ventures combine the LNG
trucking and storage capabilities of Colonial with the marketing and
storage capabilities of Cabot, and are expected to expand the
overall utilization of LNG. Completion of the sale of the Transgas
interest and implementation of the joint venture is subject to
certain regulatory approvals. Colonial will recognize a one-time
gain, net of taxes, of approximately $.35 per share at the time of
the sale, expected to occur in the first half of 1997.  The Company
has agreed to sell a 50% interest in Transgas.  Effective upon such
sale, the Company will be recognizing 50% of the net income of
Transgas on an equity basis.

                FINANCIAL AND OPERATING STATISTICS

(For the Years Ending December 31) 

Operating Revenues (In Thousands)

                         1996      1995      1994      1993      1992  

Residential           $108,879  $103,991  $104,812  $106,362  $91,412  
Commercial and 
  industrial            54,324    52,926    56,358    53,933   46,951  
Firm transportation      1,843     1,294     1,210       816      585    
Non-firm sales           2,985     3,745     2,429     3,613    4,860  
Non-firm trans
-portation                 453       424       401       409      254 
Other                    2,445     2,269     1,049     1,128      992    

Total operating 
  revenues            $170,929  $164,649  $166,259  $166,261 $145,054

Gas Sold (MMcf)
Residential             12,094    12,734    11,190    11,492   11,097  
Commercial and 
  industrial             7,469     5,826     7,526     7,443    7,445  
Non-firm                   648     1,148       729     1,030    1,508 

Total gas sales         20,211    19,708    19,445    19,965   20,050  

Gas Transported (MMcf)
Firm                     3,918     2,537     6,090     4,163    1,997  
Non-firm                 2,671     3,224     4,185     4,026    2,820  

Total gas transported    6,589     5,761    10,275     8,189    4,817   

Total gas sold and 
transported             26,800    25,469    29,720    28,154   24,867  

Gas Purchased (MMcf)
Pipeline                15,115    14,659    14,392    14,983   16,633 
Underground storage      3,346     3,270     3,112     3,501    2,666  
LNG - as liquid          1,067       844     1,129       907      564    
LNG - as vapor           1,528     1,574     1,236       917    1,095    
Propane/SNG                  1         8        25         8        9    

Total gas purchased     21,057    20,355    19,894    20,316   20,967 

Company use and other     (846)     (647)     (449)     (351)    (917)  

Available for sale      20,211    19,708    19,445    19,965   20,050       

Customers - End of period
Residential            131,286   127,419   123,077   118,918  115,115 
Commercial and 
  industrial            14,136    13,940    13,559    13,269   12,849 
Firm transportation         19        11         8         1        1      
Non-firm sales              25        27        21        21       21     
Non-firm transportation      5         2         2         2        2      

Total customers 
  - end of period      145,471   141,399   136,667   132,211  127,988 


Average Annual Mcf Sold/Customer
Residential                 96        94        96       101      103     
Commercial and 
  industrial               533       531       569       575      595    
Average Annual Bill/Customer
Residential               $868      $858      $897      $939     $839   
Commercial and 
  industrial            $3,880    $3,901    $4,260    $4,167   $3,732 
Average Revenue/Mcf

Residential             $9.00     $9.15     $9.37     $9.26    $8.16  

Commercial and 
industrial              $7.27     $7.35     $7.49     $7.25    $6.27  
Residential Heating 
  Customers as a
  % of all Residential 
  Customers               90%       90%       90%       90%      90%    
Highest Daily 
  Sendout 
  (Mcf)                170,984   199,275   204,896   184,303  157,567
Percent Colder 
  (Warmer) than 
  20-year average         3.0%      2.3%      5.0%      6.3%     3.0% 


                      SELECTED FINANCIAL DATA

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

                         1996      1995      1994      1993      1992   
Balance Sheet Data:
Assets:
Utility property-net  $250,983   $235,555  $221,685  $202,713  $183,815
Non-utility property
  -net                   5,925      5,036     3,479     3,235     4,039  
Capital leases-net       1,811      2,253     2,948     3,914     4,366  
Current assets          67,558     61,002    65,568    67,668    71,763 
Deferred charges 
  and other assets      38,135     38,575    37,668    34,588    38,939 

Total                 $364,412   $342,421  $331,348  $312,118  $302,922

Capitalization and Liabilities:
Capitalization:
Common equity         $113,906   $105,070   $99,175   $94,283   $87,771
Long-term debt          95,266     75,418    77,923    87,432    90,750 
Total Capitalization   209,172    180,488   177,098   181,715   178,521
Capital lease obligations  930      1,359     2,237     3,149     3,591  
Current liabilities     94,169    101,666    91,382    73,413    64,567 
Deferred credits 
  and reserves          60,141     58,908    60,631    53,841    56,243  

Total                 $364,412   $342,421  $331,348  $312,118  $302,922

Income Statement Data:
Operating revenues    $170,929   $164,649  $166,259  $166,261  $145,054
Cost of gas sold       (87,188)   (83,631)  (87,458)  (90,915)  (75,143) 
Operating margin        83,741     81,018    78,801    75,346    69,911 
Operating expenses 
(including income 
  taxes)               (61,547)   (59,444)  (61,284)  (56,456)  (52,760)
Utility operating 
  income                22,194     21,574    17,517    18,890    17,151 
Other income-net 
  of income taxes        2,993      1,460     1,901     1,273       958      
Interest and debt 
  expense               (8,709)    (9,270)   (8,409)   (8,141)   (7,466)
Accounting change          -         -         -        -          -
Net income             $16,478    $13,764   $11,009   $12,022   $10,643 


Capitalization Ratios:
Common equity              54%       58%       56%       52%       49%    
Long-term debt             46%       42%       44%       48%       51%

Common Stock Data:
Average shares 
  outstanding            8,432      8,294     8,119     7,931     7,728  
Income per share        $1.95      $1.66     $1.36(a)  $1.52     $1.38   

Dividends paid per share:
Common Stock            $1.295     $1.275    $1.255    $1.235    $1.213 
Class A Common Stock      -           -         -        -          -    
Per weighted average 
  common share          $1.295     $1.275    $1.255    $1.235    $1.213 
Dividend payout rate      66%         77%       92%       81%       88%   
Book value per share   $13.37     $12.56    $12.05    $11.74    $11.19 
Dividends as a percent 
  of book value           10%        10%       10%       11%       11%     
Market price per share $21.25     $20.25    $19.25    $22.50    $21.25 
Market price as a percent 
  of book value          159%       161%      160%      192%      190%   
  
Return on average 
  common equity         15.1%      13.5%     11.4%     13.2%     12.5%  

(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 Headquaters
Colonial Gas Company                
40 Market Street                    
P. O. Box 3064                      
Lowell, MA 01853-3064               
(508) 322-3000                      
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 16, 1997 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 1996 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 LLP
One Beacon Street                      
Boston, MA 02108                    
(617) 573-0100
                                    
Dividends

     The Company has paid dividends on Common Stock for 60 consecutive
years and has increased dividends each year for the past 17 years.
Common Stock dividends are payable when declared by the Board of
Directors.

Anticipated Record Date			Anticipated Payment Date   
  February 28, 1997			  March 14, 1997
  May 30, 1997				  June 13, 1997
  August 29, 1997 			  September 15, 1997
  December 1, 1997			  December 15, 1997

Dividend Reinvestment Plan

    The Company's Dividend Reinvestment and Common Stock Purchase Plan
(DRIP) provides shareholders of record with an economical and
convenient method of 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 calender quater, 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 contracting 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 preceeding business day.  Optional cash
investments must be receiced 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 1997.

Date Investment Must Be 			Investment 
Received By Transfer Agent			Dates

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

                     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 1996 and 1995, and the quarterly dividends paid per share.

                           Sales Prices          Dividends
                        High         Low         Paid per Share
_________________________________________________________________

1996                         __________________________________

The Year               $24.25       $20.00          $1.295
4th Quarter             24.00        21.25            .325
3rd Quarter             24.25        20.25            .325
2nd Quarter             24.25        20.00            .325
1st Quarter             24.00        20.25            .320


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


_________________________________________________________________

Shareholders and Record Holders

     At December 31, 1996, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,361
shareholders of record.

Market Makers

     Colonial currently has the following market makers: A. G. Edwards
& Sons, Inc.; Edward D. Jones & Co.; 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 EXHIBIT 13a]