<PAGE> 1

                                
               SECURITIES AND EXCHANGE COMMISSION
                     WASHINGTON, D.C. 20549
                    ________________________
                            Form 10-K

                           (Mark One)
      /X/  Annual report pursuant to Section 13 or 15(d) of the
                Securities Exchange Act of 1934.
              For the fiscal year ended August 31, 1997.
                                
     / / Transition report pursuant to Section 13 or 15(d) of the
                Securities Exchange Act of 1934.
       For the transition period from ________ to _________.

                  Commission File Number 1-8154

                    ESSEX COUNTY GAS COMPANY
     (Exact name of Registrant as specified in its charter)

       Massachusetts                          04-1427020
  (State of organization)         (IRS Employer Identification No.)

  7 North Hunt Road, Amesbury, Massachusetts          01913
   (Address of principal executive offices)        (Zip Code)


   Registrant's telephone number, including area code:  (978) 388-4000
                                
   Securities registered pursuant to Section 12(b) of the Act:

             Title of Class                    Exchange
         Common Stock, No Par Value           NASDAQ/NMS

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


      Indicate by check mark whether the registrant (1) has filed
all  reports required to be filed by Section 13 or 15(d)  of  the
Securities  Exchange Act of 1934 during the preceding  12  months
(or  for such shorter period that the registrant was required  to
file  such  reports),  and (2) has been subject  to  such  filing
requirements for the past 90 days.

                  Yes  / X /   No /   /

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

      The  aggregate  market value of the voting  stock  held  by
non-affiliates  on  October 31, 1997 based upon  the  last  sales
price on that date was approximately $52,483,062.

     The number of shares outstanding of Registrant's Common
Stock, no par value, was 1,693,002 at October 31, 1997.


<PAGE> 2

DOCUMENTS INCORPORATED BY REFERENCE:  Part III hereof
incorporates by reference portions of the definitive Proxy
Statement dated December 1, 1997, for the Annual Meeting of
Stockholders to be held January 20, 1998.  Part IV hereof
incorporates by reference certain of the Exhibits to the
following documents:  Registration Statement No. 2-74531 on Form
S-7, filed October 23, 1981, Registration Statement No. 33-6597
on Form S-2 filed on June 19, 1986, Registration Statement No.
33-69736 on Form S-3, filed on September 30, 1993,  Registrant's
Annual Report on Form 10-K for fiscal 1992, Registrant's Annual
Report on Form 10-K for fiscal 1993, Registrant's Quarterly
Report on Form 10-Q for the Quarter ended February 28, 1991,
Registrant's Quarterly Report on Form 10-Q for the Quarter ended
May 31, 1992, Registrant's Quarterly Report on Form 10-Q for the
Quarter ended February 28, 1995, Registrant's Quarterly Report on
Form 10-Q for the Quarter ended November 30, 1995, Registrant's
Quarterly Report on Form 10-Q for the Quarter ended February 29,
1996, Registrant's Quarterly Report on Form 10-Q for the Quarter
ended May 31, 1996, Registrant's Quarterly Report on Form 10-Q
for the quarter ended February 28, 1997 and Registrant's
Quarterly Report on Form 10-Q for the quarter ended May 31, 1997.







<PAGE> 3




                    ESSEX COUNTY GAS COMPANY

                            FORM 10-K
  
                          Annual Report
  
                   Year Ended August 31, 1997
                                
                   ---------------------------
                                
                        Table of Contents
  
Item No.                     Topic                             Page
  
                             PART I
  
   1.   Business                                                 4
   2.   Properties                                              11
   3.   Legal Proceedings                                       12
   4.   Submission of Matters to a Vote of Security Holders     12
  
                             PART II
  
   5.   Market for the Registrant's Common Equity and Related 
        Stockholder Matters                                     13
   6.   Selected Financial Data                                 13
   7.   Management's Discussion and Analysis of Financial
        Condition and Results of Operations                     14
   8.   Financial Statements and Supplementary Data             23
   9.   Changes in and Disagreements with Accountants on
        Accounting and Financial Disclosure                     41
  
                            PART III
  
  10.   Directors and Executive Officers of the Registrant      41
  11.   Executive Compensation                                  41
  12.   Security Ownership of Certain Beneficial Owners and
        Management                                              41
  13.   Certain Relationships and Related Transactions          41
  
                             PART IV
  
  14.  Exhibits, Financial Statement Schedules and Reports 
       on Form 8-K                                              41
  
       Signatures                                               43


<PAGE> 4
  
                             PART I

Item 1:  Business
                                
General


      The Company, a regulated public utility organized under the
laws  of  the  Commonwealth of Massachusetts in 1853,  purchases,
distributes and sells natural gas to residential, commercial  and
light  industrial  customers in northeastern Massachusetts.   The
Company  operates  in the cities of Haverhill,  Newburyport,  and
Amesbury  and fourteen other smaller municipalities  covering  an
area   of   approximately  280  square  miles.   The   year-round
population  of  the  Company's  service  area  was  approximately
165,000 in the 1990 Census.

      The  Company's  service  area  is  primarily  comprised  of
residential  communities with a number of  small  commercial  and
diversified light industrial businesses.  The local economy,  not
unlike  economic  conditions in general, had  been  weak  with  a
resultant  slowdown  in  new construction, especially  commercial
construction  during the early 1990s.  However, during  the  last
few   years  there  has  been  a  significant  increase  in   new
residential   construction.   New  home   construction   activity
significantly impacts the degree to which the Company is able  to
grow its customer base.
      
Sales and Customer Data

      The  Company  sells  natural gas  to  approximately  42,000
customers in its service area.  Residential users of natural  gas
generally  experience  their highest  level  of  consumption  for
heating  purposes  during  the winter months.   Accordingly,  the
Company's  sales  and  operating revenues are  sensitive  to  the
severity  of  the weather.  The Company's rates are  designed  to
recover  added costs associated with peak operations  during  the
winter  months.   In fiscal 1997, the Company's  total  operating
revenues were $53,534,734 of which approximately 64.6 percent was
derived  from residential customers, 30.1 percent from commercial
and   industrial   customers,  3.5  percent  from   interruptible
customers  and  1.8  percent  from other  sources.   During  this
period,  the Company sold 6,500,009 Dekatherms ("Dth"), of  which
approximately   56.7   percent  was  purchased   by   residential
customers,  31.7  percent by commercial and industrial  customers
and  11.6 percent by interruptible customers.  Losses and company
use amounted to 136,156 Dth for fiscal 1997.

      Set forth in the following table is information by customer
classification  showing  operating revenues,  gas  delivered  and
number of customers for the periods indicated.



<PAGE> 5
 
                                    Fiscal  Year  Ended  August  31,

                            1997      1996       1995       1994       1993
                                    (Dollars and Dths in Thousands)


Operating Revenues:
Residential-general       $ 1,907   $ 2,208    $ 2,159    $ 2,291    $ 2,160
Residential-heating        32,681    29,644     26,589     29,245     27,218
Commercial and Industrial  16,129    14,838     13,353     15,000     14,006
Interruptible               1,888     2,216      1,933        888        653
Other                         930     1,023      1,016      1,112        979
                          -------   -------    -------    -------    -------
Total                     $53,535   $49,929    $45,050    $48,536    $45,016
                          =======   =======    =======    =======    =======
Gas Delivered (Dth):
Residential-general           152       153        150        161        160
Residential-heating         3,528     3,545      3,100      3,367      3,268
Commercial and Industrial   2,062     2,068      1,874      2,039      1,972
                            -----     -----      -----      -----      -----
  Total Firm                5,742     5,766      5,124      5,567      5,400
Interruptible                 758       893        926        393        275
                            -----     -----      -----      -----      -----
  Total Sales               6,500     6,659      6,050      5,960      5,675
Losses and Company Use        136       187         90         81         92
                            -----     -----      -----      -----      -----
  Total                     6,636     6,846      6,140      6,041      5,767
                            =====     =====      =====      =====      =====

Number of Customers at year-end:
Residential-general         7,464     7,328      7,369      7,560      7,439 
Residential-heating        30,639    30,025     29,028     28,093     27,434
Commercial and Industrial   4,243     4,173      4,125      3,961      3,884
Interruptible                   2         2          2          2          2
                           ------    ------     ------     ------     ------ 
  Total                    42,348    41,528     40,524     39,616     38,759
Effective Degree Days      ======    ======     ======     ======     ======
(20-Year Average: 6,787)    6,656     6,947      6,258      7,012      6,956

     The Company's residential customers are classified as either
general or heating customers.  Residential general customers  are
those  who  do not use natural gas for space heating.  In  fiscal
1997,  residential-heating customers accounted for  approximately
61.0    percent    of    total    operating    revenues,    while
residential-general  customers accounted  for  approximately  3.6
percent  of  total operating revenues.  Operating  revenues  from
residential  customers  increased approximately  8.6  percent  to
$34,588,306 in fiscal 1997 from $31,852,683 in fiscal 1996.   The
increase  in  revenues was attributable to the higher  prices  in
fiscal  1997  compared  to  fiscal 1996  as  residential  volumes
decreased  0.5 percent.  The average rate charged to  residential
customers per Dth of gas was $9.40 and $8.61 in fiscal  1997  and
1996,  respectively.  The increase in fiscal 1997  was  primarily
due  to  a  Massachusetts Department of Public Utilities ("MDPU")
approved rate increase effective December 1, 1996 and higher  gas
costs  incurred  by  the Company.  The lower price  in  1996  was
primarily  due  to  the return to customers of pipeline  supplier
refund and previously overcollected gas costs.


<PAGE> 6
      The  Company's  commercial  and  industrial  firm  revenues
increased approximately 8.7 percent to $16,128,685 in fiscal 1997
from  $14,837,612 in fiscal 1996.  The increase was  attributable
to a 8.9 percent increase in the average price charged per Dth of
gas  from $7.18 in 1996 to $7.82 in 1997 offset by a 0.3  percent
volume decrease.  The volume decrease was largely attributable to
warmer  weather experienced during the winter in fiscal  1997  as
compared to fiscal 1996.

   The  Company  has  two interruptible customers,  only  one  of
which  purchased significant amounts of gas from the  Company  in
fiscal  1997.  Total interruptible revenues in fiscal  1997  were
$1,888,416 compared to $2,215,677 in fiscal 1996.  Sales  of  gas
to interruptible customers do not materially affect the Company's
operating  income because the Company is required to  return  all
gross profit on such sales to the Company's firm customers unless
interruptible volumes exceed a certain threshold specified by the
MDPU.  Once that threshold is attained, the Company may retain 25
percent  of  incremental gross profits.  The  threshold  was  not
attained  in  fiscal  1997.  Any gross  profit  returned  to  the
customers  is  returned through a Cost of Gas Adjustment  ("CGA")
under  which the Company is permitted to recover its  gas  costs.
The  average  price  charged  by  the  Company  to  interruptible
customers  was $2.49 per Dth and $2.48 per Dth in 1997 and  1996,
respectively.

       The  Company's  largest  customer  purchases  gas  on   an
interruptible basis and accounted for approximately  3.9  percent
of operating revenues on average over the past three fiscal years
ended  August  31, 1997.  Sales to that customer in 1997  totaled
$1,845,369  or  3.5 percent of total Company operating  revenues.
Since,  as  discussed above, most of the  gross profit earned  on
interruptible  sales is returned to firm customers,  the  Company
believes  that  the  loss  of its largest  or  any  other  single
customer  would  not  have  a material effect  on  the  Company's
results of operations.

      In  addition  to its principal business of gas  sales,  the
Company  rents water heaters and conversion burners and  performs
service  work.  Net revenues from rental operations  and  service
work  represented  less than 1.4 percent of the  total  operating
revenues  of  the Company over the past three years ended  August
31, 1997.

      During  1997, the Company added gross 1,119 new  customers.
In  fiscal 1996 and 1995, gross new customer additions were 1,120
and 1,168, respectively.

Gas Supply

      The  Company contracts for its gas supply on the  basis  of
forecasted  demand  which  is  derived  from  historical  weather
patterns recorded since 1960.  The maximum peak-day demand during
the  last  five fiscal years was 47,483 Dth on January 18,  1997.
The  Company  has  the  ability to meet a  single-day  demand  of
approximately 66,000 Dth.  Peak-day demand for gas is affected by
numerous factors, including the severity of the weather  and  the
number  of  firm customers.  Total gas sendout by the Company  in
fiscal 1997 was 6,636,165 Dth compared to 6,845,964 Dth in fiscal
1996 and 6,139,559 Dth in fiscal 1995.

      The following table shows the sources of the Company's  gas
supply requirements for the periods indicated.




<PAGE> 7

                                       Fiscal Years  Ended August 31,    
                                               (in thousands)

                                  1997     1996     1995     1994     1993

Gas Supply (Dth):
Natural gas delivered directly
by pipeline                       5,376    5,307    4,923    4,837    4,273
Underground storage withdrawn     1,007    1,062      837      833    1,290
Liquefied natural gas produced      253      477      380      371      204
                                  -----    -----    -----    -----    ----- 
Total                             6,636    6,846    6,140    6,041    5,767
                                  =====    =====    =====    =====    =====


      For  the  year  ended August 31, 1997,  approximately  85.0
percent  of  the Company's gas supply was delivered by  Tennessee
Gas  Pipeline  Company  ("TGPC"), a  division  of  Tenneco,  with
supplemental sources supplying the remainder.

      The  Company has a firm transportation contract  with  TGPC
which  provides for daily delivery of 15,728 Dth through November
1,  2000.  TGPC is currently delivering such quantities on a firm
basis  as  authorized by the Federal Energy Regulatory Commission
("FERC").   In connection with the implementation of  FERC  Order
636,  the Company has converted its natural gas purchase contract
with  TGPC  into several firm gas supply contracts directly  with
other  gas  suppliers.   These  long-term  contracts  have   been
approved  by  the  MDPU.  All contracts are with major  suppliers
that  have a demonstrated track record of performance and are  at
market  sensitive prices.  In addition to contracts  with  Aquila
Energy  and  Natural  Gas Clearinghouse for  2,500  Dth  expiring
November  1,  2002,  the  Company, through  the  efforts  of  the
Mansfield  Consortium, negotiated contracts  with  Tenngasco  for
4,410 Dth per day expiring October 31, 1999; Enron for 4,409  Dth
per  day expiring October 31, 1999; and Natural Gas Clearinghouse
for  an additional 1,909 Dth per day expiring September 1,  2002,
to  complete its transition under FERC Order 636.  See  "Item  1:
Business-Regulatory Matters-FERC Matters".

      The  Company  also  purchases gas from Boundary  Gas,  Inc.
("Boundary").   Pursuant  to  a  supply  contract  with  Boundary
expiring on January 15, 2003, the Company  may  take  up to a maximum 
of 1,610  Dth  per  day  from Boundary and may purchase up to 
587,650 Dth per year, the  annual quantity  limitation  for the 
contract.   The  Company  began  in January  1988  taking  up to 
a maximum  of  1,610  Dth  per  day. Pursuant  to  a  supply contract 
with Boundary,  the  Company  is required  to purchase 75 percent 
of this maximum amount per  year or  its  daily capacity will be 
reduced proportionately based  on the  level  actually taken by 
the Company during such year.   The Company  purchased 578,026 Dth 
in fiscal 1997 or 98.4 percent  of the   annual  quantity  limitation.   
the  Company  has  a   firm transportation  contract  with  TGPC  
for  the  delivery  of  the Boundary supply.

      The  Company  also  purchases gas  from  Alberta  Northeast
Limited  ("ANE").  In December 1991, the Company began to receive
deliveries  of 2,000 Dth per day of this Canadian  gas  from  ANE
after  ANE received approvals from the National Energy  Board  of
Canada  and the Economic Regulatory Administration of the  United
States.  Under its contract with ANE, the Company may purchase up
to 730,000  Dth  per  year, the annual quantity limitation  for  the
contract.  The contract requires the Company to purchase at least
60  percent  of the annual quantity limitation per  year  or  its
daily capacity will be reduced proportionately based on the level
actually  taken  by  the Company during such year.   The  Company
purchased  approximately  660,768 Dth  in  fiscal  1997  or  90.5
percent  of  the  contracted amount in  fiscal  year  1997.   The


<PAGE> 8
Company  has  firm  transportation contracts  with  the  Iroquois
Pipeline  and  TGPC  for  the  delivery  of  the  above-mentioned
volumes.

     The Company has two contracts for underground storage with a
total  storage  capacity  of approximately  1,140,378  Dth.   The
Company  used  a total of 1,005,957 Dth of its total  underground
storage in fiscal 1997.

      Under  a  contract expiring November 1, 2000,  the  Company
assumed  its  pro  rata share of TGPC underground  storage.   The
Company  received storage capacity of 780,928 Dth and  5,172  Dth
per  day  of deliverability, as well as the ability to  fill  the
storage  with  gas  obtained  from any  supplier.   This  service
augments  the Company's ability to meet high delivery  demand  in
the winter and to take advantage of lower off-season gas prices.

      The Company also has a contract expiring April 1, 2000 with
Consolidated  Supply Corporation for underground  storage  for  a
total  volume  of  359,450  Dth.  The contract  is  backed  by  a
transportation  contract with TGPC for  the  same  period,  which
provides  for  the withdrawal from storage and  delivery  to  the
Company of up to 4,000 Dth per day on a firm basis.

      The Company has entered into an agreement with Distrigas of
Massachusetts Corporation ("DOMAC"), which expires on October 31,
2006, that allows the Company to purchase up to 4,000 Dth per day
for  151  days of Liquefied Natural Gas as either a liquid  or  a
vapor.   The  Company, at its discretion, may increase  purchases
under the contract by up to an additional 2,000 Dth per day after
appropriate  notice.   The  Company may  also  reduce  quantities
purchased  if  normal sales dip below the normal 1994-95  heating
season sendout.

      These underground storage arrangements allow the Company to
maximize firm gas supply purchases while allowing the Company  to
take  full  advantage of the spot market gas  prices  during  the
summer  and other periods when such gas is not required  to  meet
customer demands.  The stored gas is withdrawn during periods  of
high  demand  to  assist  the Company in  meeting  firm  delivery
requirements.

      Through  a  wholly-owned subsidiary,  the  Company  owns  a
liquefied  natural  gas  ("LNG")  storage  facility  located   in
Haverhill, Massachusetts.  The LNG storage facility has a storage
capacity  of  410,000  Dth and has a daily  sendout  capacity  of
30,000 Dth.  In fiscal 1997, sendout of LNG totaled 325,026  Dth.
At  the  same location, the Company owns and operates  a  propane
plant  that  has  a storage capacity equivalent of  approximately
500,000 gallons with a total daily sendout capacity of 3,500 Dth.
In  fiscal  1997, there was no sendout of propane.   Due  to  the
comparable  cost  of  LNG and propane compared  to  pipeline  and
underground  storage, the Company uses these fuels  primarily  to
satisfy peak winter demand.

       Based  on  current  information  concerning  pipeline  and
supplemental  gas supplies, the Company expects to meet  the  gas
requirements of its firm customers for the foreseeable future.

Competition

      The  Company has no direct competition with respect to  the
retail  distribution of natural gas by pipeline  in  its  service
territory.  Massachusetts law effectively protects gas  companies
from  such  competition.  Where a gas company  exists  in  active
operation   in  Massachusetts,  no  other  person  may  construct
underground  gas mains in the public ways without  the  approval,
after  notice and hearing, of the municipal authorities  and,  in
certain  circumstances, the MDPU.  If a municipality  desires  to
enter  the  gas business, it must take certain procedural  steps,
including obtaining a favorable vote by a majority of the  voters
at  its town meeting.  The municipality would then be required to


<PAGE> 9
purchase  the utility plant of any gas company operating  in  the
area  at an agreed-upon price.  If no agreement was reached,  the
MDPU  would  make  the final determination.   Management  of  the
Company  is  not  aware of any municipality in its  service  area
which currently desires to enter the gas distribution business.

      The Company faces a changing competitive market for natural
gas. The Company's gas business competes principally with oil for
industrial  boiler uses and oil and electricity  for  residential
and commercial space heating.  Competition is primarily based  on
price.  In addition, the MDPU required the Company to submit, for
approval,  rates  dealing with transportation of third-party  gas
which  will enable large volume customers to acquire natural  gas
from  sources other than Essex County Gas. Although  the  Company
received  approval  for  these rates, no customer  selected  this
option  during  fiscal  1997.  The Company  converted  its  first
transportation  customer  in  September  1997  and  has  received
inquiries   from   approximately  30  additional   transportation
customers in October 1997.

     While the current retail price of natural gas is equal to or
slightly  higher  than the retail price of  oil  for  residential
space  heating customers, natural gas is the fuel of  choice  for
most  new  residential construction.  Natural gas has significant
environmental, operational and maintenance advantages  over  oil.
Additionally, most of the Company supply of natural gas  is  from
North American sources.  Since the mid-1970's, the retail cost of
heating residential space by natural gas in the Company's service
territory  has  been approximately the same, or  slightly  higher
than,  the  comparable  cost of heating  by  oil.   There  is  no
assurance  what, if any, the relative price differential  between
natural  gas and oil will be in the future.  Natural  gas  has  a
significant   price  advantage  over  electricity   supplied   by
investor-owned and municipal electric utilities in the  Company's
service territory.

     In the Company's service territory, the cost of heating with
natural gas for commercial and industrial customers is relatively
competitive with the cost of heating with oil.  Approximately  50
of  the  Company's commercial and industrial customers have  dual
heating  facilities  that enable them to  switch  freely  between
natural gas and oil.  As of August 31, 1997, the majority of  the
Company's dual fuel customers were using oil.

Regulatory Matters

     State

      The  Company is subject to the regulatory authority of  the
MDPU  with  respect  to  the issuance of  securities,  accounting
practices,  rates, service, contracts for the  purchase  of  gas,
territories served and related matters.

      Since  1987, the Company has filed five requests  for  rate
increases  and  has  been granted a total of $8,030,791  in  rate
relief  by  the MDPU, which amounts to 61.7 percent of the  total
requested.   The Company's most recent rate increase request  was
filed  in fiscal 1996 and approved in fiscal 1997.  The Company's
fiscal  1997 rate increase request was for an annualized increase
of  approximately $3,400,000 and the MDPU approved an  annualized
rate increase of approximately $2,100,000.  The rate increase was
effective December 1, 1996.

      The  MDPU permits Massachusetts gas companies to utilize  a
Cost of Gas Adjustment ("CGA") that permits a gas company to pass
on  to firm customers (on a current basis) increases or decreases
in  the  cost of gas supplies.  Profits from interruptible  sales
and  gas  supplier refunds are also passed on to  firm  customers
through  the CGA and no portion of the interruptible profits  are
retained  by  the  Company  unless  certain  volumes  are   sold.


<PAGE> 10
Supplemental fuel inventory and related administrative and carrying
costs are  also recovered through the CGA.  In addition, the MDPU 
allows recovery of  the  following  through the CGA:  (1) working  
capital  costs associated   with  purchased  gas  costs;  (2)   clean-up   
costs associated  with  waste materials from former  gas  manufacturing
sites; and (3) interest on the over or under collected gas costs.
The Company has the ability to release any of its unused capacity
on the Tennessee Gas Pipeline with net proceeds being returned to
firm customers through the CGA.

      Changes  in  rates  charged  to  customers  which  are  not
incorporated  in  the CGA must be approved  by  the  MDPU.   Some
relief  with respect to rate changes, such as adjustments in  the
allowed  rates of return on common equity, granting of  inflation
adjustments,  and the use of year-end rate base  calculations  in
rate  proceedings, have been granted in the past by the  MDPU  to
remedy  the  financial burden resulting from the lag between  the
historic period upon which rate decisions are based and the  date
when  the rates actually become effective.  By law, the MDPU must
act  on  a  rate proceeding within six months of filing  and  may
grant relief during the interim period.

     FERC

     The Company is not subject to direct regulation by FERC, but
is significantly affected by FERC orders that regulate interstate
pipelines serving the Company.

      Pursuant  to  FERC Order No. 636, as supplemented  by  FERC
Order   No.  636A  ("FERC  Order  636"),  TGPC  is  primarily   a
transportation pipeline and has discontinued nearly  all  of  its
activities  as  a FERC certificated merchant of  gas.   TGPC  has
previously received approval for the conversion of certain of its
sales  service  to  the  Company.  See  "Item  1:   Business--Gas
Supply."  The Company believes that the unbundling of these sales
service  arrangements will not result in material adverse changes
in  its  business  and that it will be able to  recover,  through
rates,  costs  incurred in connection with the implementation  of
FERC Order 636.

      Certain issues are still pending before FERC, such  as  the
manner  in  which  TGPC may pass on a portion of  its  transition
costs associated with Order 636.  The MDPU allows the Company  to
recover  any of the transition costs allowed by FERC through  the
CGA.

      Certain other aspects of FERC Order 636 which affect or may
affect  the  Company are pending before FERC or  are  subject  to
review  by  the courts.  These include, among other  things,  (i)
rules  for "capacity brokering" or "capacity reassignment";  (ii)
rules  for  the manner in which capacity is allocated on  various
pipelines  for transportation purposes; and (iii) rules governing
changes  in ratemaking methodologies which create uncertainty  as
to  future  transportation costs.  Until the regulatory treatment
of these issues is clarified,  the Company cannot predict the effect 
of such  issues on its business.

Environmental Matters

       The  Company  is  subject  to  local,  state  and  federal
regulations  through, among others, the Massachusetts  Department
of   Environmental   Protection  ("MDEP"),  the   United   States
Environmental  Protection  Agency  ("EPA"),  the  United   States
Department of Transportation ("DOT"), and the MDPU.  See "Item 7: 
Management's Discussion and Analysis of Financial Condition and 
Result of Operation- Regulatory and Accounting Issues.


<PAGE> 11
Pipeline Safety Matters

      The  DOT's  Office of Pipeline Safety, from time  to  time,
issues safety regulations pertaining to the installation, testing
and  repair of underground gas mains and related gas distribution
facilities by pipeline and gas distribution companies.  While the
regulations may increase the Company's expenses, the Company does
not  believe such regulations will have a material adverse effect
on  its  operating  expenses or its construction  plans  for  the
foreseeable future.

       Construction  by  a  Massachusetts  gas  company  of   any
manufacturing or storage facility or pipeline having  a  pressure
in excess of 100 pounds per square inch and a length greater than
one  mile  requires  approval by the  Energy  Facilities  Sitting
Board,  a  division  of  the  MDPU created  for  the  purpose  of
implementing  energy policies designed to provide  energy  supply
with  a  minimum  impact on the environment  and  at  the  lowest
possible cost.  Compliance with the procedures of this Board  and
other   environmental  laws  and  regulations   may   result   in
construction  delays or increased costs with  respect  to  future
expansion.   The Company does not presently have any construction
plans that would require the approval of the Board.

Personnel

      On August 31, 1997, the Company had 127 permanent employees
(including  four  part-time) 74 of whom were represented  by  the
United  Steelworkers of America, AFL-CIO-CLC, Local  12086.   The
current  three-year labor contract with the Steelworkers covering
all hourly workers extends through February 4, 1999.

Item 2: Properties

       The   Company's   property  consists  primarily   of   its
distribution  system and related facilities.  As  of  August  31,
1997,  the  Company had approximately 750 miles of gas mains  and
36,000  gas  services as well as meters, measuring and  regulator
station  equipment, and rental equipment on customers'  premises.
The Company also owns a propane plant with a storage capacity  of
500,000  gallons.  In addition, the Company, through its  wholly-
owned subsidiary, LNG Storage, Inc., owns an LNG storage facility
with a storage capacity of 410,000 Dth.

      On  August  31,  1997, the Company's  gross  utility  plant
amounted to $104,540,111 at historical cost.

      Substantially all of the properties owned by  the  Company,
other  than expressly exempted property, are subject  to  a  lien
under  the indenture securing the Company's First Mortgage Bonds.
The  Company's  gas supply contracts have also been  assigned  as
collateral security for the Company's First Mortgage Bonds.   The
indenture  calls for a trustee or receiver to take possession  of
the property if there is a default under its terms.  The property
exempted  from the lien includes cash, receivables,  supplemental
fuel  inventories,  materials  and supplies,  rental  appliances,
office furniture and equipment, and an LNG storage facility.  The
LNG  storage  facility, while unencumbered with  respect  to  the
Company's  First  Mortgage  Bonds, is encumbered  by  a  separate
mortgage note.

   The   Company   leases  its  30,000  square   foot   corporate
headquarters  building.   The lease  agreement  is  scheduled  to
expire  in  October  2005.   Annual  rental  payments  amount  to
$102,500.  The Company also has a division office that is  rented
under an agreement scheduled to expire on May 31, 1998.



<PAGE> 12
Item 3:  Legal Proceedings

      There are certain routine non-material claims incidental to
its  business  pending  against the Company,  all  of  which  are
covered  by insurance or reserves.  Management believes that  the
Company has adequate defenses against
these  claims and it is the Company's intention to contest  these
claims.   In  view  of  the  insurance coverages,  the  potential
liabilities  are not expected to materially affect the  financial
condition of the Company.

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

     None.

     Executive Officers of the Registrant

      The  following sets forth certain information as of  August
31,  1997  with  respect to Essex County Gas Company's  executive
officers.  These officers have been elected or appointed to terms
which will expire January 20, 1998:



                                                                   First
                                                                 Served as
Name                        Position                   Age        Officer

Charles E. Billups*   Chairman of the Board            68          1971
Philip H. Reardon*    President and Chief Executive 
                      Officer                          61          1992
William T. Beaton     Vice President, Human Resources
                      and Customer Services            41          1995
Wayne I. Brooks       Vice President, Distribution
                      and Engineering                  50          1985
James H. Hastings     Vice President and Treasurer     51          1985
Allen R. Neale        Vice President, Supply Planning  46          1985
John W. Purdy, Jr.    Vice President, Marketing and
                      Public Affairs                   61          1987






*Also  chairman and/or members of certain committees of the Board
of Directors.

There  are  no  family relationships among any of  the  executive
officers and directors.

Each  of  the  above has served as an officer or in a supervisory
capacity with Essex County Gas Company for the last five years.



<PAGE> 13
                             PART II

Item  5:   Market  for  Registrant's Common  Equity  and  Related
Stockholder              Matters

     The Company's Common Stock is traded on the NASDAQ/NMS under
the  symbol  "ECGC."  On October 17, 1997, the Common  Stock  was
held  by 1,314 stockholders of record.  The following table  sets
forth,  for the quarters indicated, the high and low sale  prices
as  reported  by  NASDAQ/NMS, and the cash  dividends  per  share
declared in such quarters.

                                                            Cash
                                                         Dividends
                                        Market Price     Per Share
                                       High       Low
Fiscal Year Ended August 31, 1996
     First Quarter                    $25.50    $24.25     $0.39
     Second  Quarter                   26.75     25.00      0.40
     Third  Quarter                    26.25     23.50      0.40
     Fourth Quarter                    25.50     23.50      0.40
Fiscal Year Ended August 31, 1997
     First   Quarter                  $27.00    $24.00     $0.40 
     Second Quarter                    25.75     24.25      0.41
     Third Quarter                     26.00     24.25      0.41
     Fourth Quarter                    27.00     25.25      0.41
Fiscal Year Ending August 31, 1998
     First Quarter (through 
             November 10, 1997)       $31.50    $31.50     $0.41*

*Paid on October 1, 1997 to shareholders of record on September 15, 1997.

      The  Company has paid regular dividends since 1914.  Common
Stock  dividend payments in fiscal 1997 totaled $1.63 per  share,
as  compared  to  $1.59  in fiscal 1996.   Although  the  Company
expects to continue to pay dividends at or near the current  rate
for  the  foreseeable future, the declaration of future dividends
will be at the direction of the Company's Board of Directors  and
dependent   on   business   conditions,   earnings,   contractual
restrictions and cash requirements of the Company.

Item 6:   Selected Financial Data

     The following table sets forth certain selected consolidated
financial data of the Company and its subsidiaries and the  ratio
of  earnings to fixed charges for, or as of the end of, the  five
fiscal  years ended August 31, 1997.  Due to the seasonal  nature
of the Company's business, a substantial portion of the Company's
operating revenues are derived from operations during the  second
and   third   quarters  of  each  fiscal  year.    The   selected
consolidated  financial data are qualified by  reference  to  the
consolidated financial statements and the notes thereto and other
information and data set forth elsewhere in this Annual Report or
incorporated by reference herein.



<PAGE> 14
Income Statement Data


For fiscal years ended August 31,   1997     1996     1995     1994    1993
          (000'S omitted, except for per share and ratio information)



Operating revenues                $53,535  $49,929  $45,050  $48,536  $45,016

Operating income                  $ 6,722  $ 6,669  $ 5,909  $ 5,794  $ 5,766

Income available for common stock $ 3,967  $ 3,836  $ 3,180  $ 3,302  $ 2,880

Shares of common stock outstanding,
  weighted average                  1,665    1,626    1,591    1,559    1,475

Earnings per common share         $  2.38  $  2.36  $  2.00  $  2.12  $  1.95

Cash dividends declared
  per common share                $  1.63  $  1.59  $  1.55  $  1.51  $  1.47

Ratio of earnings
  to fixed charges(1)                2.87x    2.83x    2.54x    2.83x    2.45x

         _________________________________________________________________


Balance Sheet Data


                                     1997     1996     1995    1994    1993

Long-term debt
  (excluding current portion)      $28,799  $19,765  $20,689 $21,713  $22,148

Redeemable preferred stock               -        -      336     350      364

Common stock equity                 35,409   33,023   30,709  28,870   26,985
                                   -------  -------  ------- -------  -------
TOTAL CAPITALIZATION:              $64,208  $52,788  $51,734 $50,933  $49,497
                                   =======  =======  ======= =======  =======
CAPITAL LEASE
 (EXCLUDING CURRENT PORTION)       $   551  $   605  $   654 $   700  $   742
                                   =======  =======  ======= =======  =======
TOTAL ASSETS                       $92,746  $89,772  $86,582 $83,511  $76,535
                                   =======  =======  ======= =======  =======
        _________________________________________________________________

(1)In computing the ratio of earnings to fixed charges,
"earnings" are defined as income before income taxes and fixed
charges.  "Fixed charges" consist of interest, including the
amount capitalized, interest on the obligation under the
supplemental fuel inventory, amortization of debt expense and the
estimated interest portion (one third) of rental payments.


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

        Results of Operations

        Fiscal Years Ended August 31, 1997 and 1996

        Revenues

      The Company's sales are responsive to colder weather as the
majority  of  its  customers use natural gas  for  space  heating
purposes.   The  Company  measures weather  through  the  use  of
effective degree days.  An effective degree day is calculated  by
subtracting  the  average temperature for the day,  adjusted  for
wind and cloud cover, from 65 degrees Fahrenheit.


<PAGE> 15
      Revenues  consist of three components:  firm  gas  revenues
(whereby  the  Company  must  supply  the  customer  on  demand),
interruptible  revenues  (whereby the  Company  may  curtail  gas
supplies  to  large industrial customers during the  peak  winter
season),  and  other  revenues (primarily appliance  rentals  and
service work).

     Using a twenty-year average, the Company's service territory
incurs 6,787 effective degree days in one year.  Fiscal 1997  had
6,656 effective degree days compared to 6,947 in fiscal 1996.  As
a  result,  the volume of sales to the Company's two  major  firm
customer  classes,  residential and  commercial  and  industrial,
decreased  by  0.4 percent from 5,766,690 Dth in fiscal  1996  to
5,741,885  Dth  in the current fiscal year.  The volume  decrease
was  offset by a 9.1 percent increase in the unit price and  firm
gas revenues increased to $50,716,991 in fiscal 1997 compared  to
$46,690,295  in  the  prior fiscal year.  The  higher  price  was
attributable  to  a Massachusetts Department of Public  Utilities
annualized rate increase of $2,100,000 effective December 1, 1996
and  higher  gas  costs. Firm revenues in fiscal  1997  were  8.6
percent   higher   than  in  fiscal  1996.   The   increase   was
attributable  to  the price factors discussed previously  and  an
increase of over 2.1 percent in the Company's customer base.  The
average  unit  price  of  gas sold to  all  customers,  including
interruptible  customers,  increased 10.2  percent  to  $8.09  in
fiscal  1997 from $7.34 in fiscal 1996.  For firm customers,  the
average unit price increased 9.0 percent to $8.83 in fiscal  1997
from  $8.10  in  the  prior  year.  The  Company's  interruptible
revenues   decreased  15.1  percent  as  volumes   decreased   in
interruptible sales to 758,124 Dth compared to 892,702 Dth.   The
unit  price  increased  by $0.01 to $2.49  for  fiscal  1997.  If
interruptible  volumes exceed a threshold based on  sales  during
the  prior four years, the Company may retain 25 percent  of  the
incremental  gross profit on interruptible sales and  refund  the
remaining 75 percent to the Company's firm customers.  In  fiscal
1997,  the  required  volumes  of interruptible  sales  were  not
obtained,   and  the  Company   returned  all  gross  profit   on
interruptible  sales  to  its  firm customers.  The  decrease  in
interruptible volumes did not significantly impact the  Company's
earnings.   Other revenues decreased 9.2 percent to  $929,327  in
fiscal 1997 from $1,023,417 in fiscal 1996.

      During  fiscal 1997, the Company added 1,119 new customers.
The  Company's ability to attract customers has been assisted  by
the  improving economy and resulting new construction.   Although
there is a slightly  unfavorable price comparison with oil, which
is  the  Company's  primary competition  in  the  area  of  space
heating, the environmental advantages and convenience of  natural
gas allow the Company to compete favorably.

     Operating Expenses

      The  Company's major operating expense is its cost  of  gas
which  increased 9.2 percent to $27,272,268 in fiscal  1997  from
$24,976,802 in fiscal 1996. The unit price of gas increased  12.0
percent  from  1996  to  1997.  This increase  was  offset  by  a
decrease  of  0.4  percent  in firm  volumes  of  gas  sold.  The
increased gas costs for sales to the Company's firm customers are
recovered  from those customers through a Cost of Gas  Adjustment
("CGA") which is adjusted semi-annually to reflect any changes in
gas costs.

      Operations  and maintenance expenses increased $315,594  or
2.6  percent  to  $12,291,661 in fiscal 1997 from $11,976,067  in
fiscal  1996.   This  increase  was  mainly  attributable  to  an
increase  in  meter and house regulator expense of  approximately
$107,000;   demonstrating  and  selling   expense   of   $76,000;
administrative  and  general salaries of $202,000;  environmental
costs  of  $80,000; and $91,000 in regulatory commission expense.
The  increase in meter and house regulator expense is due to  the
Company's aggressive meter exchange program in which older meters


<PAGE> 16
are  exchanged  for newer remote-read meters.   The  increase  in
demonstrating and selling expense is mainly attributable to  cash
incentives  paid  to  customers switching  to  natural  gas  from
alternative fuels and the increase in administrative and  general
salaries  expense  is mainly due to filling positions  previously
left  unfilled and pay increases granted to management personnel.
The  increase  in  environmental costs is  due  to  an  on  going
remediation of a site in Plympton, Massachusetts.  See  "Item  1:
Enviromental Matters." The increase  in  regulatory commission 
expense is due to the amortization of the  Company's December  1,  
1996 rate case expense which will continue  to  be amortized   
through  December  1,  1998.   These expenses   were partially offset 
by a decrease in pension expense of $351,000  as the Company reduced 
its pension contribution for fiscal 1997.

     Utility Plant depreciation expense increased 25.0 percent to
$3,372,714 in fiscal 1997 from $2,697,241 in fiscal 1996  as  the
Company  received regulatory approval for increasing its  utility
plant  depreciation rate to 3.70 percent from the previous year's
rate of 3.03 percent.

      Taxes, other than federal income, increased 9.3 percent  to
$1,986,927  in fiscal 1997 from $1,816,929 in fiscal 1996.   This
increase  was  primarily related to an increase  in  real  estate
taxes  due  to  assessments  on the Company's  additions  to  its
utility plant.

      Federal income taxes increased 5.4 percent to $1,889,601 in
fiscal  1997 from $1,793,360 in fiscal 1996, also reflecting  the
increase  in  the  Company's  pre-tax  earnings.   The  Company's
combined  effective tax rate for both federal  and  state  income
taxes was 36.6 percent.

      Other income, net increased by $308,923.  This increase was
primarily attributable to higher interest income on the Company's
undercollected gas costs and a gain on the sale of the  Company's
investments.

      Interest  on  long-term  debt  increased  18.9  percent  to
$2,338,112  in fiscal 1997 from $1,967,073 in fiscal 1996.   This
increase  was  primarily related to the  January  1997  issue  of
$10,000,000 in 7.28 percent First Mortgage Bonds due 2017.  Other
interest  expense  decreased 14.0 percent to $750,895  in  fiscal
1997  from  $873,198 in fiscal 1996.  This decrease was primarily
attributable  to lower levels of short-term debt  outstanding  in
fiscal 1997 as compared to fiscal 1996.  The lower level of short-
term   debt  is  a  direct  result  of  the  Company's  long-term
borrowing.

      Income available for common stock increased 3.4 percent  to
$3,966,519,  or $2.38 per share, in fiscal 1997 from  $3,835,500,
or $2.36 per share, in fiscal 1996.  Dividends per share declared
and  paid  for  fiscal  1997  and  1996  were  $1.63  and  $1.59,
respectively.

     Fiscal Years Ended August 31, 1996 and 1995

     Revenues

      Fiscal  1996  had 6,947 effective degree days  compared  to
6,258  in fiscal 1995.  As a result, the volume of sales  to  the
Company's  two  major  firm  customer  classes,  residential  and
commercial  and  industrial,  increased  by  12.6  percent   from
5,123,661  Dth  in  1995 to 5,766,690 Dth in  fiscal  1996.   The
colder  weather,  coupled with a 0.7 percent increase  in  price,
resulted   in  revenues  of  $49,929,389  in  1996  compared   to
$45,049,573  in the prior year. Firm revenues in 1996  were  10.9
percent  higher  than  in fiscal 1995.   The  increase  was  also
attributable  to  an  increase  of  nearly  3.0  percent  in  the
Company's customer base.  The average unit price of gas  sold  to


<PAGE> 17
all  customers, including interruptible customers, increased  0.7
percent  in  1996 to $7.45 from $7.40 in fiscal 1995.   For  firm
customers,  the average unit price decreased to $8.22 from  $8.36
in   the   prior  year.   The  Company's  interruptible  revenues
increased  14.6 percent as the unit price increased by  $0.40  to
$2.51 over the same period.  This price increase was offset by  a
volume  decrease in interruptible sales by 32,928 Dth to  892,702
Dth.   Under  rates  in effect in fiscal 1996,  if  interruptible
volumes  exceed a threshold based on sales during the  last  four
years,  the Company may retain 10 percent of the gross profit  on
interruptible  sales and refund the remaining 90 percent  to  the
Company's  firm customers.  In fiscal 1996, the required  volumes
of  interruptible  sales were obtained, and the Company  retained
approximately $5,000, returning the balance of all  gross  profit
on  interruptible sales to its firm customers.  The  decrease  in
interruptible volumes did not significantly impact the  Company's
earnings.   Other  revenues increased slightly to  $1,023,417  in
fiscal 1996 from $1,015,979 in fiscal 1995.

     Operating Expenses

      The  Company's major operating expense is its cost of  gas,
which  increased 10.9 percent to $24,976,802 in fiscal 1996  from
$22,525,442 in fiscal 1995.  This increase was due to  additional
volumes of gas sold.

     Operations and maintenance expenses increased 8.1 percent to
$11,976,067 in fiscal 1996 from $11,078,029 in fiscal 1995.  This
increase was mainly attributable to:  an increase of $285,000  in
employee  benefits,  other  than pensions;  $267,000  in  pension
expense   and   an   increase   of  approximately   $190,000   in
uncollectible accounts.  The increase in employee benefits, other
than  pensions,  is due to approximately $143,000  in  additional
medical expense due to higher utilization of the Company's  self-
insured  medical  plan.  In addition, the Company  increased  its
Employee Stock Ownership Plan contribution by $82,000 as well  as
a  $25,000 increase in the Company's Thrift Savings Plan  due  to
more employees participating in the Company program and receiving
matching funds.  The increase in the pension expense is primarily
due  to an additional contribution to the Company's pension trust
and  the increase in uncollectible accounts is primarily  due  to
the higher revenues recorded during the fiscal year.  The Company
also  incurred  a  one-time  additional  regulatory  expense   of
approximately  $225,000  for  conservation  and  load  management
programs and performance based ratemaking.  These increases  were
offset  by $80,000 of reduced rate case expense as the 1993  rate
case expenditures were fully amortized in December 1995.

      Utility Plant depreciation expense increased 7.9 percent to
$2,697,241  in  fiscal  1996  from  $2,500,585  in  fiscal  1995,
reflecting the ongoing investment in upgrading and expanding  the
Company's distribution system.

      Taxes, other than federal income, increased 11.2 percent to
$1,816,929  in fiscal 1996 from $1,634,216 in fiscal 1995.   This
increase  was  primarily related to an increase  in  real  estate
taxes  due  to  assessments  on the Company's  additions  to  its
utility  plant  and  state  income taxes  resulting  from  higher
pre-tax earnings.

     Federal income taxes increased 28.0 percent to $1,793,360 in
fiscal  1996 from $1,401,858 in fiscal 1995, also reflecting  the
increase  in  the  Company's  pre-tax  earnings.   The  Company's
combined effective tax rate for both federal and state income tax
purposes was 36.1 percent.

       Interest  on  long-term  debt  decreased  4.0  percent  to
$1,967,073  in fiscal 1996 from $2,048,959 in fiscal 1995.   This
decrease  was  related to the sinking fund payments of  long-term
debt.   Other interest expense increased 19.1 percent to $873,198


<PAGE> 18
in  fiscal  1996 from $732,941 in fiscal 1995. This increase  was
primarily  attributable  to  higher  levels  of  short-term  debt
outstanding and higher interest rates in fiscal 1996 as  compared
to fiscal 1995.

      Income available for common stock increased 20.6 percent to
$3,835,500,  or $2.36 per share, in fiscal 1996, from $3,179,778,
or  $2.00  per share, in 1995.  Dividends per share declared  and
paid for fiscal 1996 and 1995 were $1.59 and $1.55, respectively.

     Liquidity and Capital Resources

     Net cash provided by operating activities was $8,063,077 for
the fiscal year ended August 31, 1997.  Cash flows were generated
primarily from net income of $3,966,519, depreciation expense  of
$3,789,528,  a  decrease in taxes payable of  $1,019,266,  and  a
supplier refund due customers in the amount of $1,291,720.  These
sources  of cash were offset primarily by cash used for  deferred
income  taxes in the amount of $812,633, an increase in  accounts
receivable of $899,975 and a decrease in accounts payable in  the
amount  of $970,970.  The cash used for refundable gas  costs  to
customers  represents savings in gas costs which are returned  to
the Company's firm customers as discussed below.  The increase in
accounts  receivable  is  due  to  the  seasonal  nature  of  the
Company's business.

      Occasionally the Company receives refunds from its pipeline
supplier  as a result of regulatory action by the Federal  Energy
Regulatory   Commission  ("FERC".)   The  supplier  refunds   are
returned by the Company to customers over a twelve month  period.
During  the  twelve  months ended August 31,  1997,  the  Company
received $1,567,364 in supplier refunds.

      Due to the seasonal nature of the Company's operations,
the Company periodically borrows from banks on an unsecured short-
term  basis.   Borrowings against lines of credit  during  fiscal
1997 ranged from $55,000 to a high of $18,670,000.  At August 31,
1997,  the  available  lines  of  credit  were  $19,000,000  with
$3,313,000   outstanding.   In  addition,  a   credit   line   of
$10,000,000 was available at August 31, 1997 for the sole purpose
of  financing  the Supplemental Fuel Inventory.   At  August  31,
1997,  the  Company's Supplemental Fuel Inventory was  $4,131,520
with  outstanding  obligations under  this  credit  agreement  of
$3,807,788.   Short-term financing is typically used  to  satisfy
seasonal  cash requirements while, on an annual basis,  operating
requirements are satisfied by cash flows from operations.

      The  Company  continues to invest a significant  amount  of
capital in its distribution system to satisfy current and  future
customer demand.  Funding for the Company's construction  program
has  traditionally  been  generated  by  operations  and,  on   a
temporary basis, through short-term bank borrowings.  These short-
term  borrowings are periodically repaid with proceeds  from  the
issuance  of  long-term  debt  and equity,  including  additional
shares   of   common   stock  through  the   Company's   Dividend
Reinvestment and Common Stock Purchase Plan.  In fiscal 1997, the
Company  raised  $610,451 of common stock  through  its  Dividend
Reinvestment  and Common Stock Purchase Plan (including  $135,071
from  the  cash  infusion portion of the Plan)  and  $438,252  of
common  stock  through  the Company's  employee  stock  plan.  In
January  1997,  the Company sold $10,000,000 aggregate  principal
amount  of  First  Mortgage  Bonds, providing  the  Company  with
proceeds  of  $9,827,190  net of underwriting  fees.   Management
anticipates  that these financing sources and other sources  will
remain  available and continue to adequately serve the  Company's
needs.

      The  Company's  major  uses of cash  in  fiscal  1997  were
construction expenditures of $6,894,633, retirement of  long-term
debt  of  $854,831,  and  net  repayment  of  notes  payable   of


<PAGE> 19
$8,627,000.  In addition, dividend payments totaled $2,706,278 in
fiscal  1997.  The Company's construction expenditures  decreased
to $6,894,633 in fiscal 1997 from $8,027,623 in fiscal 1996.  The
Company's  lower  construction expenditures in fiscal  1997  were
primarily  attributable to the completion  in  1996  of  a  major
transmission line north along Route 1 from Wenham to Newburyport.
Capital  expenditures  for  fiscal  1998  are  expected   to   be
approximately $7,000,000 and annual sinking fund requirements and
maturities  of  long-term debt are scheduled to  be  $960,536  in
fiscal 1998.  The Company's planned construction expenditures and
long-term debt repayments have been, and the Company expects them
to  continue  to be, funded through cash generated by  operations
and  short-term  bank  borrowings, which the Company  anticipates
will be replaced from time to time with equity and long-term debt
financings.

      On  August 31, 1997, the Company's capitalization consisted
of  49.0  percent  common  stock equity and  51.0  percent  debt,
including  short-term debt and obligations under the supplemental
fuel  inventory credit agreement.  In order to contribute to both
stability   and  the  ability  to  market  new  securities   when
appropriate, the Company attempts to maintain a balanced  capital
structure.

     Regulatory and Accounting Issues

      The Company's revenues are based on rates regulated by  the
MDPU.   These rates are designed to allow the Company to  recover
its  operating  costs  and  provide an opportunity  to  earn  a
reasonable  rate  of  return on investor  supplied  funds.   Once
approved,  the  Company's  rates are adjusted  by  a  CGA  which,
subject  to approval by the MDPU, permits the Company  to  change
rates  to recover gas costs and certain other costs on a  dollar-
for-dollar basis.  The CGA is also used as a mechanism to  reduce
charges  to  firm  customers by the margin  earned  on  sales  to
interruptible customers.  In September 1996 the Company  received
approval for a rate increase of $2,100,000 which became effective
December 1, 1996.  As part of a settlement approved by the  MDPU,
the  Company  has increased its depreciation rate to  an  average
rate  of  3.70  percent effective December 1,  1996  based  on  a
depreciation   study.   The  effect  of  this   change   in   the
depreciation  rate  increased, on an annual  basis,  depreciation
expense in fiscal 1997 by approximately $600,000.

     The Company has received notification that the Massachusetts
Department  of  Environmental Protection ("MDEP") has  reason  to
believe that the Company may be a potentially responsible  party,
along with several other parties, with respect to alleged release
of  hazardous materials at sites in Plympton, Massachusetts.  The
Company  does  not  currently  have  sufficient  information   to
reasonably estimate the amount of the final liability for cleanup
costs  or  other damages or expenses at such sites.  The  Company
believes  it  should be permitted to recover these costs  through
rates.


<PAGE> 20
      The  Company  or its predecessors previously operated  four
manufactured  gas plants and one storage facility  (collectively,
"MGPs")  at sites in Massachusetts.  It is possible that  in  the
manufacturing process some or all of the MGPs may have discharged
certain  substances on the sites which may now be  deemed  to  be
hazardous.   The Company has not ascertained the  extent  of  any
hazardous  substance contamination on these sites  from  the  MGP
operations.  The Environmental Protection Agency ("EPA") and MDEP
have  recently  begun  to  focus on the  potential  environmental
hazards of MGPs.  To the Company's knowledge, neither the EPA nor
the  MDEP have issued any orders to clean up any of the Company's
MGP  sites.  In 1995 an investigation which reported the presence
of  certain  compounds was conducted at one of the Company's  MGP
sites.   As a result, a second, more intensive investigation  was
conducted  in fiscal 1997 to determine the level of contamination
and  to assess whether any remediation was required.  The Company
had also been informed that certain materials had been discovered
on  properties adjacent to a second site currently owned  by  the
Company.  These adjacent properties have been classified  by  the
MDEP  as  a  location to be investigated.  Based  on  preliminary
investigation, the Company currently believes that it may not  be
liable  for  cleanup costs associated at the adjacent  properties
unless  such liability is based on down-gradient status; however,
the  Company may be liable for cleanup costs associated with  the
parcel  presently  owned by the Company.  The  Company  does  not
currently   possess  sufficient  information  to  determine   the
probability  or  the cost of the potential remediation,  however,
the  MDPU  provides  for  the recovery through  the  CGA  of  all
environmental response costs associated with this and  any  other
MGP  sites over seven-year amortization periods without a  return
on  the  unamortized  balance.   The  1990  MDPU  agreement  also
provides  for  no  further investigation on the prudency  of  any
Massachusetts gas utility's past MGP operations.

      The natural gas industry is in the process of transitioning
from a highly regulated environment to a competitive environment.
Pursuant  to  FERC  Order  636, as supplemented  by  Order  636A,
pipeline  companies  have unbundled pipeline sales,  storage  and
transportation services.  FERC Order 636 was implemented  by  the
Company's  pipeline  supplier,  Tennessee  Gas  Pipeline  Company
("TGPC"),  on September 1, 1993.  As a result, TGPC is  providing
transportation service only.  The Company now contracts  for  its
own  gas  supply through a consortium of gas companies  and  pays
monthly  demand charges to TGPC for the availability of  pipeline
capacity  and  transportation charges  for  gas  transport.   The
Company  pays charges for the cost of gas delivered and  for  gas
inventory  charges  to  reserve  volumes  of  gas  inventory   in
connection  with  substantially all of  its  long-term  firm  gas
purchase agreements.

      FERC  Order 636 has also required pipelines to adopt a  new
rate design that has shifted the recovery of the pipeline's fixed
costs  to a monthly demand charge for firm transportation service
and away from recovery of costs of service on a volumetric basis.

     FERC Order 636 also allows the pipeline companies to recover
transition  costs  incurred as they restructure  their  services.
TGPC began direct billing these costs to the Company on September
1,  1993  as  a  component of the demand charges.  The  Company's
current  estimate  of  its  obligation for  transition  costs  is
approximately  $401,000 and is based upon FERC approved  filings.
This  estimated  liability  has been included  in  the  Company's
financial  statements  at  August 31,  1997,  together  with  the
related regulatory asset.  The MDPU has approved the recovery  of
Gas Supply Realignment costs from all firm customers.

     The MDPU has received comments and proposals from interested
persons  on  how  incentive regulation  could  improve  upon  the
existing  framework of utility regulation.  Although to date  the
MDPU  has not issued directives, it is expected that in the  near


<PAGE> 21
future, incentive ratemaking, in some form, will be instituted in
the Commonwealth of Massachusetts.

      The  accompanying consolidated financial statements conform
to  generally accepted accounting principles applicable  to  rate
regulated  enterprises and reflect the effects of the  ratemaking
process  in  accordance  with SFAS No.  71,  Accounting  for  the
Effects  of  Certain  Types of Regulation.  Assuming  a  cost-of-
service   based  regulatory  structure,  regulators  may   permit
incurred costs, normally treated as expenses, to be deferred  and
recovered  through  future  revenues.   Through  their   actions,
regulators may also reduce or eliminate the value of an asset, or
create  a  liability.  If any portion of the Company's operations
were  no  longer subject to the provisions of SFAS No. 71,  as  a
result  of  a  change  in  the cost-of-service  based  regulatory
structure  or  the effects of competition, the Company  would  be
required  to  write  off regulated assets and  liabilities.   The
Company   continues  to  believe  that  its  use  of   regulatory
accounting remains appropriate.

     The "Year 2000" Issue

      The  Company has assessed the impact of the year 2000 issue
and  is  currently  modifying  its  computer  system  to  process
transactions relating to the year 2000.  Anticipated spending for
this  modification  will  be expensed  as  incurred  and  is  not
expected  to  have a significant impact on the Company's  ongoing
results of operations.

     New Accounting Standards

      In  March  1997,  the Financial Accounting Standards  Board
issued   SFAS  No.  128,  Earnings  Per  Share.   SFAS  No.   128
establishes  standards for computing and presenting earnings  per
share and applies to entities with publicly held common stock  or
potential  common stock.  This statement is effective for  fiscal
years  ending after December 15, 1997 and early adoption  is  not
permitted.   When adopted, the statement will require restatement
of  prior years' earnings per share.  The Company will adopt this
statement  for  its  fiscal  year  ended  August  31,  1998.   In
addition, the Company believes that the adoption of SFAS No.  128
will not have a material effect on its financial statements.


      The  American  Institute  of Certified  Public  Accountants
issued   a   Statement  of  Position  ("SOP")96-1,  Environmental
Remediation  Liabilities.  The SOP's objective  is  to  make  the
timing  of  the  recognition  of environmental  obligations  more
uniform  by  discussing  the  estimation  process  and  providing
benchmarks  to aid in determining when to recognize environmental
liabilities.   The  SOP is effective for the  Company  in  fiscal
1998.   The Company does not expect that the adoption of the  SOP
will  have a material impact on the Company's financial  position
or results in operations.

     Forward Looking Statements

      The  Private  Securities  Litigation  Reform  Act  of  1995
encourages the use of cautionary statements accompanying forward-
looking  statements.  The preceding Management's  Discussion  and
Analysis   of  Financial  Condition  and  Results  of  Operations
included  forward-looking  statements concerning  the  impact  of
transportation  customers  on  the Company's  profitability;  the
impact of changes in the cost of gas and of the CGA mechanism  on
total margin; projected capital expenditures and sources of  cash
to  fund  expenditures;  and  estimated  costs  of  environmental
remediation  and  anticipated  regulatory  approval  of  recovery
mechanisms.   The  Company's future results, generally  and  with

<PAGE> 21
respect  to  such forward-looking statements, may be affected  by
many factors, among which are uncertainty as to the precise rates
for  transportation of gas that will be allowed by the regulators
and   transportation-only  customers;  uncertainty  as   to   the
regulatory allowance of recovery of changes in the cost  of  gas;
uncertain  demands for capital expenditures and the  availability
of   cash  from  various  sources;  and  uncertainty  as  to  the
regulatory approval of the full recovery of environmental  costs,
transition costs, and other regulatory assets.


<PAGE> 23
Item 8:  Financial Statements and Supplementary Data

        (a)  Financial Statements Required by Regulation S-X


                   CONSOLIDATED STATEMENTS OF INCOME


                                           Fiscal Years Ended August 31,

                                          1997         1996         1995

OPERATING REVENUES                     $53,534,734  $49,929,389  $45,049,573
Less:  Cost of gas                      27,272,268   24,976,802   22,525,442
                                       -----------  -----------  -----------
   Operating margin                     26,262,466   24,952,587   22,524,131
                                       -----------  -----------  -----------
OPERATING EXPENSES:
  Operations and maintenance expenses   12,291,661   11,976,067   11,078,029
  Depreciation                           3,372,714    2,697,241    2,500,585
  Taxes, other than federal income       1,986,927    1,816,929    1,634,216
  Federal income taxes                   1,889,601    1,793,360    1,401,858
                                       -----------  -----------  -----------
       TOTAL OPERATING EXPENSES         19,540,903   18,283,597   16,614,688
                                       -----------  -----------  -----------
OPERATING INCOME                         6,721,563    6,668,990    5,909,443
OTHER INCOME, NET                          337,707        1,997        6,202
                                       -----------  -----------  -----------
INCOME BEFORE INTEREST CHARGES           7,059,270    6,670,987    5,915,645
                                       -----------  -----------  -----------
INTEREST CHARGES:
  Interest on long-term debt             2,338,112    1,967,073    2,048,959
  Amortization of deferred debt expense     30,578       27,499       27,081
  Other interest expense                   750,895      873,198      732,941
  Allowance for funds used
    during construction                    (26,834)     (46,143)     (92,428)
                                       -----------  -----------  -----------
        TOTAL INTEREST CHARGES           3,092,751    2,821,627    2,716,553
                                       -----------  -----------  -----------
NET INCOME                               3,966,519    3,849,360    3,199,092
ANNUAL REDEEMABLE
PREFERRED DIVIDEND REQUIREMENTS                  -      (13,860)     (19,314)
                                       -----------  -----------  ----------- 
INCOME AVAILABLE FOR COMMON STOCK      $ 3,966,519  $ 3,835,500  $ 3,179,778
                                       ===========  ===========  ===========
SHARES OF COMMON STOCK OUTSTANDING
(WEIGHTED AVERAGE)                       1,664,677    1,626,315    1,591,372
                                         ---------    ---------    ---------
EARNINGS PER COMMON SHARE                   $ 2.38       $ 2.36       $ 2.00
                                            ------       ------       ------
CASH DIVIDENDS DECLARED PER COMMON SHARE    $ 1.63       $ 1.59       $ 1.55
                                            ------       ------       ------
            



                   CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
            
                                         Fiscal Years Ended August 31,

                                     1997             1996           1995
BALANCE AT BEGINNING OF YEAR     $13,833,767      $12,576,695    $11,857,299
Net income                         3,966,519        3,849,360      3,199,092
                                 -----------      -----------    -----------
      TOTAL                       17,800,286       16,426,055     15,056,391
                                 -----------      -----------    -----------
Cash dividends declared:
  Redeemable preferred stock               -           13,860         19,314
  Common stock                     2,706,278        2,578,428      2,460,382
                                 -----------      -----------    -----------
              TOTAL                2,706,278        2,592,288      2,479,696
                                 -----------      -----------    -----------
BALANCE AT END OF YEAR           $15,094,008      $13,833,767    $12,576,695
                                 ===========      ===========    ===========



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



<PAGE> 24
                       CONSOLIDATED BALANCE SHEETS


                                ASSETS
                                

                                            August 31,     August 31,
                                              1997           1996

UTILITY PLANT, AT COST                    $104,540,111     $ 98,603,784
Less: Accumulated depreciation              25,021,795       22,290,175
                                          ------------     ------------
NET UTILITY PLANT                           79,518,316       76,313,609 
                                          ------------     ------------
Other property and investments                 718,838          633,515
                                          ------------     ------------
CAPITALIZED LEASE (NET OF ACCUMULATED
 AMORTIZATION OF $518,975 1N 1997 AND
 $469,406 IN 1996)                             604,822          654,391
                                          ------------     ------------  
                               
CURRENT ASSETS:
 Cash and cash equivalents                     434,930          303,526  
 Accounts receivable:
   Customers (net of allowance for
   uncollectible accounts of $772,000
   in 1997 and $653,000 in 1996)             2,275,005        1,654,808
   Other                                       389,526          229,189
 Income tax refunds receivable                       -          874,000
 Supplemental fuel inventory                 4,131,520        4,047,421
 Materials and supplies (at average cost)      560,493          512,330
 Prepaid deferred income taxes                 100,105          328,066
 Prepayments and other                         622,024          622,502
 Recoverable gas costs                         320,909          470,766
                                           -----------       ----------      
    TOTAL CURRENT ASSETS                     8,834,512        9,042,608
                                           -----------       ----------   
DERRED CHARGES:
 Regulatory assets                           1,790,966        2,464,691
 Unamortized debt expense and other          1,278,367          663,119
                                           -----------      -----------
    TOTAL DEFERRED CHARGES                   3,069,333        3,127,810
                                           -----------      -----------
                                          $ 92,745,821     $ 89,771,933
                                          ============     ============


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



<PAGE> 25
                   CONSOLIDATED BALANCE SHEETS
                                
                 CAPITALIZATION AND LIABILITIES



                                          August 31,          August 31,
                                             1997                1996

COMMON STOCK EQUITY                      $35,408,645         $33,022,947
LONG-TERM DEBT, LESS CURRENT PORTION      28,799,000          19,765,535
                                         -----------         -----------
    TOTAL CAPITALIZATION                  64,207,645          52,788,482
                                         -----------         -----------
NONCURRENT OBLIGATIONS UNDER 
   CAPITAL LEASE                             550,939             604,823
                                         -----------         -----------
CURRENT LIABILITIES:
 Current portion of long-term debt           960,535             923,831
 Current obligation under capital lease       53,883              49,568
 Obligations under supplemental  
   fuel inventory                          3,807,788           3,358,010
 Notes payable, banks                      3,313,000          11,940,000
 Accounts payable                          3,092,859           4,063,829
 Accrued interest                            803,237             937,988
 Taxes payable                               157,098              11,832
 Accrued transition costs                    401,465             890,432
 Supplier refund due customers             1,567,364             275,644
 Other                                       320,308             176,681
                                         -----------         -----------  
       TOTAL CURRENT LIABILITIES          14,477,537          22,627,815
                                         -----------         -----------
COMMITMENTS AND CONTINGENCIES
DEFERRED CREDITS:
 Accumulated deferred income taxes         8,941,079           9,951,085
 Unamortized investment tax credit         1,141,132           1,210,896
 Deferred directors' fees                  1,106,358             991,503
 Other                                     2,321,131           1,597,329
                                         -----------         ----------- 
       TOTAL DEFERRED CREDITS             13,509,700          13,750,813
                                         -----------         -----------
                                         $92,745,821         $89,771,933
                                         ===========         ===========





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




<PAGE> 26
                   CONSOLIDATED STATEMENTS OF CASH FLOWS


                                

                                           Fiscal Years Ended August 31,
                                           1997         1996         1995
OPERATING ACTIVITIES:
 NET INCOME                           $ 3,966,519  $ 3,849,360   $ 3,199,092
 Adjustments to reconcile net income  -----------  -----------   -----------
  to net cash:
 Depreciation, including amounts 
  related to non-utility operations     3,789,528    3,130,712     2,920,476
 Provisions for uncollectible accounts    119,441       57,792      (208,797)
 Deferred income taxes                   (812,633)   1,950,962        40,876
 Amortization                              (1,915)       7,943         8,390
 Noncash compensation associated 
    with ESOP                              75,000      150,000       225,000
Changes in current assets and liabilities:
 Accounts receivable                     (899,975)    (242,390)      546,304
 Inventories including fuel              (132,262)   2,512,221       294,854
 Prepayments and other                        478     (271,842)      (33,922)
 Accounts payable                        (970,970)   1,077,522        55,729
 Supplier refund obligations            1,291,720   (2,179,095)      792,927
 Taxes payable/receivable               1,019,266     (802,472)      488,000
 Recoverable (refundable) gas costs       149,857   (2,960,944)    1,719,994
 Other, net                               469,023      (53,011)      658,391
                                      -----------  -----------   ----------- 
     Total adjustments                  4,096,558    2,377,398     7,508,222
                                      -----------  -----------   -----------
         NET CASH PROVIDED BY 
           OPERATING ACTIVITIES         8,063,077    6,226,758    10,707,314
                                      -----------   ----------    ----------
INVESTING ACTIVITIES:
 Utility capital expenditures          (6,894,633)  (8,027,623)   (6,967,340)
 Payments for retirements of property,
   plant and equipment, net               (99,602)    (258,352)      (66,497)
 Purchase of investment                  (570,113)           -             -
 Sale of investment                       570,113            -             -
                                       ----------    ---------    ---------- 
   NET CASH USED IN INVESTING 
     ACTIVITIES                        (6,994,235)  (8,285,975)   (7,033,837)
                                       ----------   ----------    ----------
FINANCING ACTIVITIES:
 Dividends paid                        (2,706,278)  (2,592,288)   (2,479,696)
 Issuance of common stock               1,048,703      856,007       814,126
 Issuance of long-term debt             9,827,190            -             -
 Retirements of preferred stock                 -     (336,000)      (14,000)
 Principal retired on long-term debt     (854,831)    (828,758)     (855,304)
 Changes in supplemental fuel inventory   449,778   (1,773,143)   (1,297,617)
 Changes in notes payable, banks       (8,627,000)   7,050,000       390,000
 Payment of ESOP debt                     (75,000)    (150,000)     (225,000)
   NET CASH PROVIDED BY (USED IN)      ----------   ----------    ----------
     FINANCING ACTIVITIES                (937,438)   2,225,818    (3,667,491)
                                       ----------   ----------    ----------
Net increase in cash and cash 
   equivalents                            131,404      166,601         5,986
Cash and cash equivalents at 
   beginning of year                      303,526      136,925       130,939
CASH AND CASH EQUIVALENTS AT           ----------   ----------    ----------
   END OF YEAR                         $  434,930   $  303,526    $  136,925
                                       ==========   ==========    ==========
SUPPLEMENTAL DISCLOSURES:
 Cash paid during the year for:
 Interest (net of amount capitalized)  $3,227,502  $2,708,961     $2,517,015
                                       ----------  ----------     ----------
 Income taxes                          $2,682,465  $1,407,476     $1,743,197
                                       ----------  ----------     ----------




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




<PAGE> 27

                 CONSOLIDATED STATEMENTS OF CAPITALIZATION



                                            August 31,          August 31,
                                               1997                1996
COMMON STOCK EQUITY:
  Common stock, no par value, 5,000,000 
   authorized shares. Issued and 
   outstanding 1,685,318 shares at 
   August 31, 1997 and  1,642,490  issued 
   and outstanding at August  31,  1996.    $20,320,890       $19,234,915
  Unrealized gain (loss)on investments 
   available for  sale,  net                     (6,253)           29,265 
  Retained earnings                          15,094,008        13,833,767
                                            -----------       ----------- 
                                             35,408,645        33,097,947
                                            -----------       -----------
  Less:  Shares held by ESOP purchased
         with debt                                    -            75,000
                                            -----------       -----------
         Total   common   stock   equity     35,408,645        33,022,947
                                            -----------       -----------
LONG-TERM DEBT:
FIRST MORTGAGE BONDS:
  10 1/4 percent, due serially 
     from 1994 to 2003                        4,200,000         4,800,000
  10.10 percent, due serially 
     from 2010 to 2020                        8,000,000         8,000,000
   7.28 percent due serially  
     from 2008 to 2017                       10,000,000                 -
                                            -----------       -----------
                                             22,200,000        12,800,000
MORTGAGE NOTE:                              -----------       -----------
   8 1/2 percent, due serially 
     from 1976 to 1997                          360,535           609,366
                                            -----------       -----------
DEBENTURES:
   8 5/8 percent, due 2006                    2,245,000         2,245,000 
   8.15  percent, due 2017                    4,954,000         4,960,000
                                             ----------       -----------
                                              7,199,000         7,205,000
ESOP LOAN GUARANTEE:                         ----------       -----------
   7.0 percent due serially 
     from 1987 to 1996                                -            75,000 
                                             ----------       -----------
          TOTAL DEBT                         29,759,535        20,689,366
   Less:  Current portion maturing 
          and payable                           960,535           923,831
   TOTAL LONG-TERM DEBT                      28,799,000        19,765,535
                                            -----------       ----------- 
   TOTAL CAPITALIZATION                     $64,207,645       $52,788,482
                                            ===========       ===========






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



<PAGE> 28
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


A.   Summary of Significant Accounting Policies

     General

      Essex County Gas Company is a public utility engaged in the
distribution and sale of natural gas for residential,  commercial
and industrial uses.  Its service area is located in northeastern
Massachusetts.

     Regulation

      The  Company  is subject to regulation by the Massachusetts
Department of Public Utilities ("MDPU") with respect to its rates
and  accounting  practices. The accounting  policies  conform  to
generally  accepted accounting principles as applied to regulated
public  utilities  and  reflects the effects  of  the  ratemaking
process  in  accordance  with Statement of Financial  Accounting,
Standard  No.  ("SFAS")  71, "Accounting  for  Certain  Types  of
Regulation".   Under  SFAS No. 71, a utility  is  allowed  to  defer
certain costs that otherwise would be expensed in recognition  of
the ability to recover them in future rates.

     The Company has established regulatory assets in cases where
the  MDPU has permitted or is expected to permit the recovery  of
specific  costs  over  time.  As of August  31,  1997,  principal
regulatory   assets  include  (1)  approximately   $401,000   for
transition  costs  associated with FERC Order 636,  (2)  $347,000
related  to  a  settlement payment for a supplemental  retirement
plan,   and  (3)  $415,000  related  to  deferred  income  taxes.
Included  in  deferred  credits  is  a  regulatory  liability  of
$708,000  related to deferred income taxes. Assuming  a  cost-of-
service   based  regulatory  structure,  regulators  may   permit
incurred costs, normally treated as expenses, to be deferred  and
recovered  through  future  revenues.   Through  their   actions,
regulators may also reduce or eliminate the value of an asset, or
create  a  liability.  If any portion of the Company's operations
were  no  longer subject to the provisions of SFAS No. 71,  as  a
result  of  a  change  in  the cost-of-service  based  regulatory
structure  or  the effects of competition, the Company  would  be
required  to  write  off regulated assets and  liabilities.   The
Company   continues  to  believe  that  its  use  of   regulatory
accounting remains appropriate.

     Principles of Consolidation and Presentation

      The  consolidated financial statements include the accounts
of  LNG  Storage, Inc., a wholly owned subsidiary.  All  material
intercompany balances and transactions have been eliminated.

     Cash equivalents are defined as investments with an original
maturity of three months or less.

     Operating Revenues

      Revenues from the sale of gas are based on rates authorized
by  the MDPU and are recorded in the period the bill is rendered.
Meters  are  read  and  bills  are  rendered  on  a  cycle  basis
throughout the month.  As a result, the volumes of gas  delivered
to customers in any period may be more or less than the usage for
which customers are billed.

      The Company's rates include a Cost of Gas Adjustment Factor
which  permits the Company to recover the difference between  gas


<PAGE>29
costs  incurred by the Company and gas costs billed to customers.
The  amount of the difference is deferred for accounting purposes
and expensed when reflected in billings in subsequent periods.

     Utility Plant

      Utility  plant  and other property are stated  at  original
cost.    The   cost  of  additions  to  utility  plant   includes
contracted  work, direct labor and material, allocable  overhead,
allowance for funds used during construction and indirect charges
for  engineering  and  supervision.   Expenditures  for  ordinary
maintenance and repairs are charged to expense as incurred.

      Depreciation for financial reporting purposes is calculated
on a straight-line basis.  The annual provision for depreciation,
based  on the average depreciable property, was equivalent  to  a
composite depreciation rate of 3.53 percent for fiscal  1997  and
3.03  percent  for  fiscal 1996 and 1995.  As  part  of  an  MDPU
approved  rate increase effective December 1, 1996,  the  Company
increased its annual depreciation rate to 3.70 percent from  3.03
percent.   The 3.53 percent rate for 1997 represents pre December
1,  1996  depreciation at the former rate and post  November  30,
1996 depreciation at the current rate.  The cost of Utility Plant
retired  or  otherwise  disposed of, in the  ordinary  course  of
business, together with costs of removal less salvage, is charged
to accumulated depreciation.

     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.

     Earnings Per Share

      In  March  1997,  the Financial Accounting Standards  Board
issued   SFAS  No.  128,  Earnings  Per  Share.   SFAS  No.   128
establishes  standards for computing and presenting earnings  per
share and applies to entities with publicly held common stock  or
potential  common stock.  This statement is effective for  fiscal
years  ending after December 15, 1997 and early adoption  is  not
permitted.   When adopted, the statement will require restatement
of  prior years' earnings per share.  The company will adopt this
statement  for  its  fiscal  year  ended  August  31,  1998.   In
addition, the Company believes that the adoption of SFAS No.  128
will not have a material effect on its financial statements.

     Reclassifications

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

B.   Supplemental Fuel Inventory

      The  Company, with MDPU approval, finances its supplemental
gas  inventory  through  a single purpose  financing  arrangement
extending   through  December  31,  2000.  The  credit  agreement
provides  for  a  total commitment of up to  $10,000,000  and  is
secured  by  storage  gas.  Financing resulted  in  an  effective
interest  cost  to the Company of 6.1 percent for  1997  and  6.5
percent in 1996 based on average borrowing.


<PAGE> 30

C.   Common Stock

     Common stock activity for the three-year period ended August
31, 1997, is as follows:

                                                        Additional
                               Number of     Common      Paid-in
                                Shares       Stock       Capital
BALANCE, AUGUST 31, 1994      1,572,062  $ 3,930,155   $13,532,990

   Dividend reinvestment plan    19,276       48,190       389,246
   Amortization of capital
     stock expense                    -            -        51,408
   Employee stock plans          13,054       32,635       280,208
   Sale of common stock           2,669        6,673        57,174
                              ---------    ---------    ----------

BALANCE, AUGUST 31, 1995      1,607,061    4,017,653    14,311,026

   Dividend reinvestment plan    19,754      366,787       100,916
   Amortization of capital
     stock expense                    -       50,229             -
   Employee stock plans          11,319      226,881        52,370
   Sale of common stock           4,356       97,283        11,770
   Conversion to no par value         -   14,476,082   (14,476,082)
                              ---------   ----------    ----------
BALANCE, AUGUST 31, 1996      1,642,490   19,234,915             -

   Dividend reinvestment plan    19,733      475,380             -
   Amortization of capital
     stock expense                    -       37,272             -
   Employee stock plans          17,794      438,252             -
   Sale of common stock           5,301      135,071             -
                              ---------   ----------     ----------
BALANCE, AUGUST 31, 1997      1,685,318  $20,320,890   $         -
                              =========   ==========     ==========


    Conversion of Stock to No Par Value

    The shareholders approved conversion of Common Stock from $2.50
par value to no par value effective September 15, 1995.

D.   Restriction on Retained Earnings

     Under the terms of the indenture securing the First Mortgage
Bonds, retained earnings in the amount of $5,260,241 as of August
31,  1997,  were unrestricted as to the payment of cash dividends
on  common  stock and the purchase, redemption or  retirement  of
shares of common stock.

E.   Interim Financing and Long-term Debt

     The Company periodically borrows from banks on an unsecured,
short-term basis.  At August 31, 1997, the Company had $3,313,000
of  outstanding  notes payable with a weighted  average  interest
rate  of  6.2  percent under available lines of  credit  totaling
$19,000,000.  The annual commitment fees related to  these  lines
of  credit  are between 1/4 percent and 3/8 percent on the  total
amount of the line.


<PAGE> 31
      Substantially  all plant assets are pledged  as  collateral
under  the  terms of the indenture of First Mortgage Bonds.   The
8-1/2  percent Mortgage Note represents an obligation secured  by
the  liquefied  gas storage facility in Haverhill, Massachusetts.
In  accordance with the terms of the indenture of First  Mortgage
Bonds, the Note Purchase Agreement of the sinking fund notes  and
the  Mortgage  Note, the Company is required  to  make  specified
sinking  fund payments and other maturities of long-term debt  of
$960,536 in 1998, $600,000 in 1999, $600,000 in 2000, $600,000 in
2001 and $17,005,000 thereafter.

F.   Disclosure About Fair Values of Financial Instruments

     The estimated fair values of the Company's long-term debt at
August   31,  1997  and  1996  are  $35,202,321  and  $22,901,111,
respectively,  as compared to the carrying value  of  $28,799,000
and  $19,765,535, respectively.  The estimated fair value of  the
Company's long-term debt is estimated based on the quoted  market
prices  for  the same or similar issues or on the  current  rates
offered  to the Company for debt of the same remaining  maturity.
The  fair  value  shown above does not purport to  represent  the
amount at which these obligations could be settled.

      The  carrying value of cash approximates fair value because
of the short maturity of those instruments.

   G.    Income Taxes

   The components of the provision for income taxes are as follows:

                             1997          1996              1995
FEDERAL
     Current             $2,258,000    $   294,144        $1,469,957
     Deferred              (298,635)     1,569,000             2,000
     Amortization of 
      investment tax  
       credit               (69,764)       (69,784)          (70,099)
                          ---------      ---------         ---------
       TOTAL FEDERAL      1,889,601      1,793,360         1,401,858
STATE                     ---------      ---------         ---------
     Current                454,643         58,643           292,615
     Deferred               (64,000)       321,000               445
                          ---------      ---------         ---------
       TOTAL STATE          390,643        379,643           293,060
                          ---------      ---------         ---------
TOTAL INCOME TAXES       $2,280,244     $2,173,003        $1,694,918
                          =========      =========         =========

      A  reconciliation of federal income taxes calculated at the
statutory  rate  with income tax expense shown in  the  financial
statements  for each of the three years ended August  31,  is  as
follows:


<PAGE> 32
                                     1997         1996        1995

Federal statutory rate               34.0%        34.0%       34.0%
                                     ====         ====        ====
Federal income tax
  expense at statutory rates      $2,117,753    $2,048,628  $1,663,963

Increase (decrease) in taxes 
   resulting from:
     Amortization of investment
      tax credit                     (69,764)      (69,784)    (70,099)

     State taxes, net of
      federal  benefit               257,824       250,564     199,980
     Other                           (25,569)      (56,405)    (98,926)
                                   ---------     ---------   ---------

TOTAL INCOME TAX EXPENSE          $2,280,244    $2,173,003  $1,694,918
                                   =========     =========   =========
EFFECTIVE INCOME TAX RATE               36.6%         36.1%       34.6%
                                        ====          ====        ====

     The Company follows the provisions of Statement of Financial
Accounting  Standards  No.  109, "Accounting  for  Income  Taxes"
("SFAS  109"). SFAS No. 109 requires the recognition of deferred  tax
liabilities  and assets for the expected future tax  consequences
of  events that have been included in the financial statements or
tax   returns.   Under  this  method,  deferred  tax  assets  and
liabilities  are determined based on the difference  between  the
financial statement and tax basis of assets and liabilities using
enacted  tax rates in effect in the year in which the differences
are  expected  to  reverse.  A regulatory asset of  $415,000  was
established for the deferred taxes not previously recovered as  a
result of the flow through to customers for temporary differences
in  prior  years.   This  balance is  being  recovered  over  the
estimated  lives  of  the  property.  A regulatory  liability  of
$708,000  was  established  for the tax  benefit  of  unamortized
investment tax credits, which SFAS No. 109 requires to be treated  as
a  temporary  difference.  This benefit is  being  passed  on  to
customers  over  the  lives  of  property  giving  rise  to   the
investment  credits.  Significant items making  up  deferred  tax
assets  and deferred tax liabilities at August 31, 1997 and  1996
are as follows:
        
                                                   1997           1996
Liabilities
  Utility Plant-primarily depreciation         $11,399,390    $10,779,608
  Other                                            476,162        602,814
                                               -----------    -----------
        TOTAL LIABILITIES                       11,875,552     11,382,422
                                               -----------    -----------
Assets
  Investment tax credits                           708,053        751,340
  Deferred directors fees                          423,624        379,646
  Unbilled revenue                                 317,513        208,870
  Reserve for uncollectible receivables            295,688        249,954
  Supplier refund                                  600,144              -
  Capitalized cost - inventory                     443,739              -
  Other                                            245,817        169,593
                                                ----------     ----------
        TOTAL ASSETS                             3,034,578      1,759,403
                                                ----------     ----------
ACCUMULATED DEFERRED INCOME TAXES, NET         $ 8,840,974    $ 9,623,019
                                                ==========     ==========


<PAGE> 33
   The net year-end deferred income tax liabilities above are net of
current   deferred   tax   assets  of   $100,105   and   $328,066
respectively, which are included in prepaid income taxes  in  the
accompanying Consolidated Balance Sheets.


H. Leases

    The  Company is obligated under various lease agreements  for
certain  facilities  and  equipment used  in  operations.   Total
expenditures  under  operating  leases  were  $298,789  in  1997,
$315,152  in  1996 and $289,721 in 1995.  A summary  of  property
classified as capital leases as of August 31, 1997 and 1996 is as
follows:

                                               1997           1996

         Buildings                          $1,123,796     $1,123,797

         Less: Accumulated depreciation        518,974        469,406
                                            ----------     ----------
                                            $  604,822     $  654,391
                                            ==========     ==========

   In accordance with the rate treatment allowed by the MDPU, the
depreciation expense of $49,568, $45,600, and $41,948, along with
interest  of $52,931, $56,850 and $60,502 related to the  capital
lease,  is  included in other operating expenses  for  the  years
ended August 31, 1997, 1996 and 1995, respectively.

    The  Company also has various operating lease agreements  for
equipment,  vehicles  and office space.   The  remaining  minimum
annual  rental  commitment for these and all other non-cancelable
leases is as follows:

                                 Capital Leases       Operating Leases

   1998                              $102,500              $266,750
   1999                               102,500               101,500
   2000                               102,500                68,250
   2001                               102,500                16,750
   2002                               102,500                   855
   Thereafter                         324,406                     -
                                     --------              --------
   Total minimum lease payments       836,906              $454,105
                                                           ========
   Less: Amount representing 
           interest                   232,084
                                     --------
                                     $604,822
                                     ========
I. Employee Benefits

   Pension Plans

    The Company has two pension plans covering substantially  all
employees.   The actuarial method for determining annual  pension
cost is the Projected Unit Credit method.


<PAGE> 34
Net pension cost for 1997, 1996 and 1995 consist of the following
components:


                                        1997        1996        1995


   Service cost - benefits
      earned during the year        $  286,362  $  268,542   $  231,741
   Interest cost on projected
       benefit obligations             752,921     722,354      668,107
   Actual return on plan assets     (1,741,366) (1,125,838)    (887,022)
   Net amortization and deferral     1,134,587     609,010      412,504
                                    ----------  ----------    ---------
      NET PENSION COST              $  432,504  $  474,068    $ 425,330
                                    ==========  ==========    =========


   The expected long-term rate of return on assets was 8.5 percent
in  1997,  1996 and 1995.  The discount rate used in  determining
the  actuarial present value of the projected obligation was  7.5
percent  in 1997 and 8.0 percent in 1996 and 1995.  The  expected
rate  of pay increase was 5.0 percent in 1997 and 6.0 percent  in
1996 and 1995.


   The following table sets forth the funding status of the pension
plans and amounts recognized in the Company's balance sheet based
on measurement dates of August 31, 1997 and 1996:
 
                                                   1997      1996
     
Actuarial present value of benefit
obligations (in thousands):
Vested benefit obligation                        $ 9,257   $ 8,198
                                                 =======   =======

Accumulated benefit obligation                   $ 9,817   $ 8,734
                                                 =======   =======
Projected benefit obligation
for service rendered to date                     $10,689   $ 9,708
Plan assets, primarily listed stocks,
corporate bonds and U.S. bonds,
at fair value                                     10,212     9,083
                                                 -------   -------
Projected benefit obligation in excess
of plan assets                                      (477)     (625)
Unrecognized net gain                             (1,586)     (776)
Unrecognized prior service cost                    1,635     1,399
Adjustment required to recognize
  additional minimum liability                       (44)        -
Unrecognized net obligation at transition             (7)        -
                                                 -------   -------
Accrued pension liability                        $  (479)  $    (2)
                                                 =======   =======
Assets in the pension plan are currently held in mutual funds.

   Employee Stock Ownership Plan

    On  September 1, 1986, the Company created an Employee  Stock
Ownership  Plan  and  Trust ("ESOP").   The  Company  contributes
annually  to  a trust an amount equal to principal plus  interest


<PAGE> 35
and any other fees net of interest income earned by the trust and
dividends on unallocated shares.  The Trust was created primarily
to acquire shares of the Company's common stock for the exclusive
benefit  of  the  participants (substantially  all  nonbargaining
employees).   During  fiscal 1987, the Trust borrowed  $1,500,000
and  acquired 82,800 shares, as adjusted for a two-for-one  stock
split  effective  April  1,  1987, of  the  Company's  previously
unissued common stock.  The loan is guaranteed by the Company and
the  final payment of $75,000 was due in October, 1996.  The ESOP
was  recorded  as  a  liability  and  the  offsetting  debit  was
accounted  for  as  a  reduction of common stock  equity  in  the
accompanying consolidated balance sheets.  Interest  was  payable
monthly  at  a floating rate which was 80 percent of the  current
prime  rate.   The charge to income, which equals  the  Company's
contribution,   for  1997  was  $174,006  which  includes   8,000
additional  shares  to  be issued in early  1998,  for  1996  was
$223,477, and for 1995 was $141,359.  Interest on ESOP  debt  was
$839  for  1997, $8,055 for 1996 and $17,365 for 1995.  Dividends
on  unallocated  ESOP  shares used to pay debt  service  for  all
periods  presented  was $5,699 for 1997,  $12,738  for  1996  and
$27,193 for 1995.

   Savings Plan

    The  Company has a thrift savings plan in which  the  Company
matches one-half of employee contributions with the match  capped
at  three percent. The Company contributed approximately $169,000
to  the  Plan in 1997, $132,000 to the Plan in 1996, and $119,000
to the plan in 1995.

   Postretirement Benefits Other Than Pension

    The  Company follows the provisions of Statement of Financial
Accounting   Standards   No.  106,  Employers'   Accounting   for
Postretirement Benefits Other Than Pensions ("SFAS  106").   This
standard  requires  the  accrual of the  expected  cost  of  such
benefits  during  the  employee's  years  of  service   and   the
recognition  of an actuarially determined postretirement  benefit
obligation  earned  by existing retirees.   The  assumptions  and
calculations  involved  in  determining  the  accrual   and   the
accumulated  postretirement benefit obligation  closely  parallel
pension  accounting requirements.  Prior to  1994,  the  cost  of
postretirement benefits was recognized on a pay as you go  basis.
The cumulative effect of the implementation of SFAS No. 106 as of
September  1, 1994 is being amortized over 20 years. The  Company
is currently recovering the full SFAS No. 106 cost in rates.

   The net periodic postretirement benefit cost for the year ended
August 31, 1997, 1996 and 1995 is as follows:
                                         1997      1996      1995

   Service cost                        $103,140  $104,469  $ 84,550
   Interest cost                        345,298   316,398   284,861
    (Return) loss on plan assets        (35,551)  (22,610)   13,066
   Net amortization and deferral        177,071   189,435   157,634
                                       --------  --------  --------
    TOTAL POSTRETIREMENT BENEFIT COST  $589,958  $587,692  $540,111
                                       ========  ========  ========


<PAGE> 36
   The funded status of the Company's postretirement benefit plan
using  a  measurement date of July 1, 1997, 1996 and 1995  is  as
follows:

                                          1997          1996         1995

Accumulated postretirement benefit 
   obligation:
      Retirees                        $(3,213,120)  $(2,834,211) $(2,972,713)
      Fully eligible active Plan 
       participants                      (162,946)     (108,839)    (118,200)
      Other active Plan participants   (1,481,702)   (1,274,960)  (1,264,135)
                                      ------------  ------------ ------------
                                       (4,857,768)   (4,218,010)  (4,355,048)
      Plan assets at fair value         1,386,073       886,580      557,939
Accumulated postretirement obligation ------------  ------------ ------------
    greater than Plan assets           (3,471,695)   (3,331,430)  (3,797,109)
Unrecognized transition obligation      3,261,880     3,465,748    3,669,616
Unrecognized (gain) loss                    8,588      (310,951)      (3,021)
                                      ------------  ------------  -----------
        ACCRUED POSTRETIREMENT 
           BENEFIT COST               $  (201,227)  $  (176,633)  $ (130,514)
                                      ============  ============  ===========
    The  weighted  average discount rate used in determining  the
accumulated postretirement benefit obligation was 7.5 percent  in
1997,  1996 and 1995.  The annual increase in the cost of covered
health  care  benefits for 1997 was 8.75 percent and 7.0  percent
for  participants under age 65 and over age 65, respectively, and
for   1996  and  1995  was  9.5  percent  and  7.5  percent   for
participants  under 65 and over 65, respectively.  This  increase
gradually decreases to 5 percent in the year 2007 and thereafter.
A 1.0 percent increase in the assumed health care cost trend rate
would  have increased the cost computed under SFAS 106 by $37,931
and  increased the accumulated postretirement benefit by $443,713
as of August 31, 1997.

   The Company has established two Voluntary Employee Beneficiary
Associations ("VEBA") trusts pursuant to section 501(c)9  of  the
Internal  Revenue Code to fund these benefits.  The Company  also
created  a  subaccount to its pension plan  pursuant  to  section
401(h)  of the Internal Revenue Code to satisfy a portion of  its
postretirement    benefit   obligation.    The    Company    made
contributions  to the trusts and the subaccount during  1997  and
1996 totaling $560,241 and $541,483, respectively.  Assets in the
VEBA  trusts  are held in cash reserve accounts.  Assets  in  the
subaccount  to  the  pension plan are currently  held  in  listed
stocks, corporate bonds and government bonds.

   Stock Option Plans

   In 1995 the Company adopted an Incentive Stock Option Plan  and a
Non-Qualified  Stock Option Plan (the Plans) under which  options
may  be  granted to officers and key employees.  Options  for  an
aggregate  of 100,000 shares may be granted under the Plans  with
not  more than 25,000 shares granted during any one year  to  any
individual.  During 1995, the Company granted a total  of  20,000
shares  under  the Incentive Stock Option Plan and  4,000  shares
under  the  Non-Qualified Stock Option Plan at a price of  $24.25
with  exercise  dates  beginning  February  9,  1996  and  ending
February 9, 2000.  No options were granted, exercised or  expired
during either 1996 or 1997.  At August 31, 1997, options covering
24,000  shares were outstanding and 9,600 were exercisable  under
the  Plans.   In  addition, 76,000 shares  under  the  Plans  are
available for future grants.

   In October 1995, the Financial Accounting Standards Board issued
SFAS No. 123, Accounting for Stock-Based Compensation, which sets
forth a fair market value based method of recognizing stock-based
compensation expense.  As permitted by SFAS No. 123, the  Company
has  elected to continue to apply APB No. 25 to account  for  its
stock  option plans.  Had compensation cost for awards in  fiscal
1995,  1996  and 1997 under the Company's Incentive Stock  Option
Plan and Non-Qualified Stock Option Plan been determined based on
the  fair  market  value at the grant dates consistent  with  the
method  set forth under SFAS No. 123, the effect would have  been
as follows:



<PAGE> 37
                                  1997           1996           1995

   Net income:
     As reported              $3,966,519      $3,835,500     $3,179,778
     Pro forma                $3,958,518      $3,821,855     $3,166,977
   Earnings per share:
     As reported              $     2.38      $     2.36     $     2.00
     Pro forma                $     2.37      $     2.35     $     1.99

   The fair value of each option granted is estimated on the grant
date  using the Black-Scholes option pricing model.  The weighted
average  grant date fair value of options granted was $1.88.   In
computing  the above pro forma amounts the Company has assumed  a
risk-free  interest rate of 6.2 percent, an expected  life  of  4
years,  an  expected volatility of 11.5 percent and  an  expected
dividend yield of 6.2 percent.

J. Commitments and Contingencies

   Construction Expenditures

   The Company's construction expenditures in connection with its
continuing  construction  program  are  presently  estimated   at
$7,000,000  for  1998,  $8,000,000 for  1999,  and  approximately
$7,000,000 in each of the following three years.

   Gas Supply, Transportation and Storage

   The Company has various long-term gas supply, transportation and
storage  contracts  with minimum cost provisions.   Under  these
contracts,  the  Company is obligated to make specified  minimum
payments.  Based on current rates and/or agreements, the minimum
annual payments under these contracts are as follows:

                                                 1997 to 2000

Pipeline Transportation Demand                    $ 3,859,635

Underground Storage Demand                            458,945

Underground Storage Transportation                    707,937

Pipeline Gas Inventory Charge                       2,847,048

Gas Supply Realignment Charges                        401,464
                                                   ----------
                                                  $ 8,275,029
                                                   ----------
   FERC Order 636 allows the pipeline companies to recover transi
tion  costs  created as they buy out of long-term,  fixed  price
contracts.  Tennessee Gas Pipeline Company began direct  billing
these  costs to the Company on September 1, 1993 as a  component
of the demand charges.  At August 31, 1997, the transition
costs are estimated at $401,000 and will be billed in fiscal 1998
subject  to  modification  and/or refund  based  on  final  FERC
approval   of   pipeline  transition  costs  to  be   recovered.
Negotiations are continuing with the pipeline of  several  other
issues.  As a result, the Company is unable to predict its final
obligation  at this time; however, based on these and subsequent
settlement  activities, the Company will adjust  its  regulatory
assets and liability accounts accordingly.  The MDPU has allowed
recovery  of  these  transition costs  through  the  cost-of-gas
adjustment clause.


<PAGE> 38
   Litigation Matters

   The Company is a defendant in various civil actions, which are
covered by insurance and reserves.  Based on the advice of  legal
counsel,  management  believes  that  the  Company  has  adequate
defenses  against  these claims and, in  view  of  the  insurance
coverage, the potential liability would not materially effect
the financial condition or the results of operations of the Company.

   Environmental Matters

    The  Company has received notification that the Massachusetts
Department  of Environmental Protection ("MDEP"), has  reason  to
believe that the Company may be a potentially responsible  party,
along with several other parties, with respect to alleged release
of  hazardous materials at sites in Plympton, Massachusetts.  The
Company  does  not  currently  have  sufficient  information   to
reasonably estimate the amount of the final liability for cleanup
costs  or  other damages or expenses at such sites.  The  Company
believes  it  should be permitted to recover these costs  through
rates.

    The  Company  or  its predecessors previously  operated  four
manufactured  gas plants and one storage facility  (collectively,
"MGPs")  at sites in Massachusetts.  It is possible that  in  the
manufacturing process some or all of the MGPs may have discharged
certain  substances on the sites which may now be  deemed  to  be
hazardous.   The Company has not ascertained the  extent  of  any
hazardous  substance contamination on these sites  from  the  MGP
operations.  The Environmental Protection Agency ("EPA") and MDEP
have  recently  begun  to  focus on the  potential  environmental
hazards of MGPs.  To the Company's knowledge, neither the EPA nor
the  MDEP have issued any orders to clean up any of the Company's
MGP  sites.  In 1995 an investigation which reported the presence
of  certain  compounds was conducted at one of the Company's  MGP
sites.   As a result, a second, more intensive investigation  was
conducted  in fiscal 1997 to determine the level of contamination
and  to assess whether any remediation was required.  The Company
had also been informed that certain materials had been discovered
on  properties adjacent to a second site currently owned  by  the
Company.  These adjacent properties have been classified  by  the
MDEP  as  a  location to be investigated.  Based  on  preliminary
investigation, the Company currently believes that it may not  be
liable  for  cleanup costs associated at the adjacent  properties
unless  such liability is based on down-gradient status; however,
the  Company may be liable for cleanup costs associated with  the
parcel  presently  owned by the Company.  The  Company  does  not
currently   possess  sufficient  information  to  determine   the
probability  or  the cost of the potential remediation,  however,
the  MDPU  provides  for  the recovery through  the  CGA  of  all
environmental response costs associated with this and  any  other
MGP  sites over seven-year amortization periods without a  return
on  the  unamortized  balance.   The  1990  MDPU  agreement  also
provides  for  no  further investigation on the prudency  of  any
Massachusetts gas utility's past MGP operations.




<PAGE> 39
               REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


  To:  The Board of Directors of Essex County Gas Company

We  have audited the accompanying consolidated balance sheets and
statements  of  capitalization of Essex  County  Gas  Company  (a
Massachusetts  corporation) as of August 31, 1997 and  1996,  and
the  related consolidated statements of income, retained earnings
and  cash  flows for each of the three years in the period  ended
August 31, 1997.  These consolidated financial statements are the
responsibility  of the Company's management.  Our  responsibility
is   to  express  an  opinion  on  these  consolidated  financial
statements based on our audits.

We  conducted  our  audits in accordance with 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
significant  estimates made by management, as well as  evaluating
the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to
above  present  fairly, in all material respects,  the  financial
position  of Essex County Gas Company as of August 31,  1997  and
1996,  and  the results of its operations and its cash flows  for
each  of the three years in the period ended August 31, 1997,  in
conformity with generally accepted accounting principles.

Our audits were made for the purpose of forming an opinion on the
basic financial statements taken as a whole.  The schedule listed
in  the  index to consolidated financial statements is  presented
for  purposes  of  complying  with the  Securities  and  Exchange
Commission's  rules  and  is not a part of  the  basic  financial
statements.   The  schedule has been subjected  to  the  auditing
procedures   applied  in  the  audits  of  the  basic   financial
statements  and,  in our opinion, fairly state, in  all  material
respects, the financial data required to be set forth therein  in
relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEN LLP
Boston, Massachusetts
October 24, 1997
                                
                                
                                
<PAGE> 40                                
Item 8:  Financial Statements and Supplementary Data

        (b) Selected Quarterly Financial Data



                                


                                
                                 YEAR ENDED AUGUST 31, 1997


                                    Three  Months  Ended
                                      ________________

                   November 30, February 28, May 31,   August 31,
                       1996        1997       1997       1997       Total

Operating revenues  $8,142,501 $23,220,840 $16,659,598 $5,511,795 $53,534,734
Operating income       471,157   3,814,227   1,971,507    464,672   6,721,563
Income (loss)
  applicable to 
   common shares      (260,669)  3,131,438   1,256,125   (160,375)  3,966,519
Earnings (loss) per 
   common share            (.16)       1.89         .75       (.10)      2.38
Dividends declared per 
   common share             .40         .41         .41        .41       1.63
Stock price range:
         High             27.00       25.75       26.00      27.00
         Low              24.00       24.25       24.25      25.25






                                
                               YEAR ENDED AUGUST 31, 1996


                                   Three  Months  Ended


                   November 30, February 29,  May 31,   August 31,
                       1995        1996        1996       1996       Total

Operating revenues $ 6,962,014 $22,632,458 $15,546,131 $ 4,788,786 $49,929,389
Operating income       536,242   3,701,969   1,733,463     697,316   6,668,990
Income (loss)    
   applicable to              
   common shares      (208,087)  2,973,836   1,054,867      14,884   3,835,500
Earnings (loss) per  
   common share           (.13)       1.83         .65         .01        2.36
Dividends declared
   per common share        .39         .40         .40         .40        1.59
Stock price range:
         High            25.50       27.38       26.25       25.75
         Low             24.25       25.00       23.50       23.00


<PAGE> 41
Item 9:   Changes in and Disagreements with Accountants on Accounting
          and Financial Disclosure

     None.

                            PART III

Item 10:  Directors and Executive Officers of the Registrant

     The information required by Item 401 and 405 of Regulation
S-K is herein incorporated by reference to Registrant's Proxy
Statement dated December 1, 1997, for the Annual Meeting of
Stockholders to be held on January 20, 1998, under the caption
"Nominees for Director"; "Board of Directors and Committees"; and
"Section 16(a) Beneficial Ownership Reporting Compliance."

Item 11:  Executive Compensation

     The information required by Item 402 of Regulation S-K is
herein incorporated by reference to Registrant's Proxy Statement
dated December 1, 1997, for the Annual Meeting of Stockholders to
be held on January 20, 1998, under the caption "Directors'
Compensation"; "Executive Compensation"; "Employee Plans and
Agreements - Pension Plan Table"; and "Compensation Committee
Report on Executive Compensation".

Item 12:  Security Ownership of Certain Beneficial Owners and
Management

     The information required by Item 403 of Regulation S-K is
herein incorporated by reference to Registrant's Proxy Statement
dated December 1, 1997, for the Annual Meeting of Stockholders to
be held on January 20, 1998, under the caption "Securites
Ownership of Certain Beneficial Owners and Management".

Item 13:  Certain Relationships and Related Transactions

     The information required by Item 404 of Regulation S-K is
herein incorporated by reference to Registrant's Proxy Statement
dated December 1, 1997, for the Annual Meeting of Stockholders to
be held on January 20, 1998, under the caption "Compensation
Committee Interlocks and Insider Participation" and "Certain
Transactions."

                             
                             PART IV

ITEM 14:   Exhibits, Financial Statement Schedules and Reports on
Form 8-K

A)   Documents filed as part of this report:

      1.    The Financial Statements of the Company, on pages  23
            through 38, and the Report of Arthur Andersen LLP on  page
            39 therein.

     2.   Financial Statement Schedules.

            The   following  supplementary  financial   statement
schedules  required by Rule 5-04 of Regulation  S-X,  and  report



<PAGE> 42
thereon,  are  filed  as  part of this  Form  10-K  on  the  page
indicated below:

Schedule                                                  Page  No. in
Number    Description                                      this Report

II        Consolidated Valuation and Qualifying Accounts 
            for the three years ended August 31, 1997            42
          Report ofIndependent Public Accountants                39

Schedules other than the one listed above are either not 
required or not applicable, or the required information is 
shown in the financial statements or notes thereto.

     3.   Exhibits required by Item 601 of Regulation S-K.

          See Exhibit Index on pages 44 through 47.


B)   Reports on Form 8-K.

     No  reports on Form 8-K have been filed during the  quarter
     ended August 31, 1997.

C)   Exhibits required by Item 601 of Regulation S-K.

     See Exhibit Index on pages 44 through 47.

D)   Financial Statement Schedules.

     CONSOLIDATION VALUATION AND QUALIFYING ACCOUNTS
                    (In thousands)


     Reserves which are deducted in the balance sheets from
     assets to that they supply


                                     Charged   Charged
                        Balance at     to        to                 Balance
Year ended              beginning   costs and   other               at end of
August 31  Description  of period   expenses accounts(1) Deductions  period
  1997    Allowance for
        doubtful accounts  $653       $614       $167       $662      $772
  1996    Allowance for
        doubtful accounts  $595       $613       $164       $719      $653
  1995    Allowance for
        doubtful accounts  $804       $422       $230       $861      $595
     __________________________________________
     (1)Represents recoveries on accounts previously written off



<PAGE> 43
                                
                           SIGNATURES

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

Date:   November 25, 1997               by   /s/ James H. Hastings
                                       Vice President and Treasurer

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

Signature                      Title                         Date


/s/ Charles E. Billups         Chairman of the Board


/s/ Philip H. Reardon         President and
                              Chief Executive Officer


/s/ James H. Hastings         Vice President and Treasurer
                               (Principal Financial and
                                   Accounting Officer)

/s/ Benjamin C. Bixby         Director


/s/ Daniel A. Burkhardt       Director


/ / Edward J. Curtis          Director


/s/ Dorothy J. Dotson         Director


/s/ Richard P. Hamel          Director


/s/ Robert S. Jackson         Director


/s/ Eric  H. Jostrom          Director

/ / Robert L. Meade           Director


/s/ Kenneth L. Paul           Director


/s/ Richard L. Wellman        Director



<PAGE> 44
                          Exhibit Index
                                
The exhibits listed below are filed herewith or are incorporated
by reference to other filings.


Exhibit
Number         Description

3.1      Restated Articles of Organization of Essex County
         Gas Company.10

3.2      Bylaws of Essex County Gas Company.11

4.1      Indenture dated as of June 1, 1986 between the Company and
         Centerre Trust Company of St. Louis, Trustee.2

4.2      Eleventh Supplemental Indenture dated as of September 15,
         1988, providing for a 10 1/4 percent Series due 2003.1

4.3      Twelfth Supplemental Indenture dated as of December 1,
         1990, providing  for a 10.10 percent  series  due 2020.4

4.4      Revolving Credit Agreement dated November 14, 1995 between
         Essex County Gas Company and the First National Bank of Boston.12

4.5      Fifteenth Supplemental Indenture dated as of December 1,
         1996 providing for a 7.28 percent Series due 2017.13

10.1     LNG Storage, Inc., Lease Indenture of Mortgage and Deed of
         Trust dated April 10, 1972.1

10.2     Haverhill Familee Investment Corporation  -  Lease  of
         Corporate Headquarters dated November 1, 1975.1

10.3     Arlington Trust Company - Purchase  Contract,  Credit
         Agreement, Trust Agreement and Storage  Agreement
         dated October 1, 1980.1

10.4     Consolidated Gas Supply Corporation - Underground Storage
         Contract dated February 18, 1980.1

10.5     Penn-York Energy Corporation - Storage Services Agreement
         dated December 21, 1984.1

10.6     Canadian Gas Transportation Contract between Tennessee Gas
         Pipeline Company and Essex County Gas Company dated
         December 1, 1987.3



<PAGE> 45



Exhibit
Number         Description

10.7      Phase 2 Gas Sales Agreement between Boundary Gas and Essex
          County Gas Company dated September 14, 1987.3

10.8      Amendment to the Agreement for the Sale of Gas between Bay
          State Gas Company and Essex County Gas Company dated May 6, 1988.3

10.9      Agreement for the Liquefaction of Gas between Bay State Gas
          Company and Essex County Gas Company dated March 14, 1988.3

10.10     Bond Purchase Agreement dated December 1, 1990,
          between Allstate Life Insurance Company of New
          York, and Essex County Gas Company.4

10.11     Iroquois Gas Transmission System, L.P. Gas
          Transportation Contract for Firm Reserved Service
          dated February 7, 1991.3

10.12     Alberta  Northeast Gas Limited (ANE),  Gas  Sales
          Contract Agreement No. 1 dated February 7, 1991.5

10.13     Aquila  Energy  Marketing Corporation  Gas  Sales
          Agreement dated June 5, 1992.5

10.14     Natural Gas Clearinghouse Gas Sales Agreement dated
          June 8, 1992.5

10.15     Tennessee Gas Pipeline Transportation Contract dated
          February 7, 1991.6

10.16     Tennessee Gas Pipeline Company Gas Storage Contract
          (SS-NE) TGP002099STO dated November 10, 1991.6

10.17     Tennessee  Gas Pipeline Company  Storage  Service
          Transportation Contract TF-4175 dated October 28, 1991.6

10.18     Form of employment agreement between the Company and
          each of the following officers:   Wayne  I. Brooks,  
          Vice President; John W. Purdy, Jr., Vice President; James H.  
          Hastings, Vice President and Treasurer;  Allen R. Neale, 
          Vice President; and Cathy E. Brown, Clerk.  These contracts are 
          identical to those submitted with the Annual  Report  for  
          each  with  the  exception  of  compensation amounts.2*

10.19     Employment Agreement between the Company and Philip H. Reardon,
          President, dated November 19, 1992.7*

10.20     Gas Transportation Agreement between Essex County Gas Company and
          Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule)
          dated September 1, 1993.8


<PAGE> 46
Exhibit
Number         Description

10.21          Gas Transportation Agreement between Essex County Gas
               Company and Tennessee Gas Pipeline Company (for use
               under FT-A Rate Schedule) dated August 25, 1993.8

10.22          Gas Transportation Agreement between Essex County Gas
               Company and Tennessee Gas Pipeline Company (for use
               under Transportation Service   "CGT-NE"   Rate
               Schedule) dated September 1, 1993.8

10.23          Gas Transportation Agreement between Essex County Gas
               Company and Tennessee Gas Pipeline Company (for use
               under FT-A Rate Schedule) dated September 1, 1993.8

10.24          Gas Transportation Agreement between Essex County Gas
               Company and Tennessee Gas Pipeline Company (for use
               under  Rate  Schedule  FS) dated  September  1, 1993.8

10.25          Amendment to Employment Agreement between the Company
               and  Philip  H. Reardon, President, dated  March  3, 1994.*

10.26          Amendment to Employment Agreement between the Company
               and John W. Purdy, Jr., Vice President, dated March 3, 1994.*

10.27          Amendment to Employment Agreement between the Company
               and Wayne I. Brooks, Vice President, dated March  3, 1994.*

10.28          Amendment to Employment Agreement between the Company
               and  Allen R. Neale, Vice President, dated March  3, 1994.*

10.29          Amendment to Employment Agreement between the Company
               and James H. Hastings, Vice President and Treasurer,
               dated March 3, 1994.*

10.30          Amendment to Employment Agreement between the Company
               and Cathy E. Brown, Corporate Clerk, dated March  3, 1994.*

10.31          Essex County Gas Company Supplemental Retirement Plan
               for Philip H. Reardon effective January 1, 1994.*

10.32          Employment Agreement between the Company and William
               T. Beaton, Vice President, dated June 7, 1995.*

27             Financial Data Schedule.

   B)          Reports on Form 8-K.

               No reports on Form 8-K have been filed during the quarter
               ended August 31, 1997.


*Denotes Management Contract.


<PAGE> 47

1Previously  filed  as  an  exhibit to Registrant's  Registration
 Statement on Form  S-7,  filed  October  23, 1981, File  No.  2-74531  
 and  is incorporated herein by this reference.

2Previously  filed  as  an  exhibit to Registrant's  Registration
 Statement  on Form S-2,    filed June 19, 1986, File No.  33-6597
 and is incorporated herein by this reference.

3Previously filed as an exhibit to Registrant's 10-Q filed for the
 quarter ended   February 29, 1996, and is incorporated herein  by
 this reference.

4Previously filed as an exhibit to Registrant's 10-Q filed for the
 quarter ended  February  28,  1991, and is incorporated  herein  by  this
 reference.

5Previously filed as an exhibit to Registrant's 10-Q filed for the
 quarter ended May 31, 1992, and is incorporated herein by this reference.

6Previously filed as an exhibit to Registrant's 10-K filed for the
 fiscal year ended August 31, 1992, and is incorporated herein  by
 this reference.

7Previously  filed as an exhibit to Registrant's  Form  S-3,  No.
 33-69736, filed on September 30, 1993, and is incorporated herein
 by this reference.

8Previously filed as an exhibit to Registrant's Form 10-K filed for
 the fiscal year ended August 31, 1993, and is incorporated herein
 by this reference.

9Previously filed as an exhibit to Registrant's Form 10-Q filed for
 the quarter ended May 31, 1996 and is incorporated herein by this
 reference.

10Previously filed as an exhibit to Registrant's Form 10-Q filed for
  the quarter ended February 28, 1995 and is incorporated herein by
  this reference.

11Previously filed as an exhibit to Registrant's Form 10-Q filed for
  the quarter ended May 31, 1997 and is incorporated herein by this
  reference.

12Previously filed as an exhibit to Registrant's Form 10-Q filed for
  the quarter ended November 30, 1996 and is incorporated herein by
  this reference.

13Previously filed as an exhibit to Registrant's Form 10-Q filed for
  the quarter ended February 28, 1997 and is incorporated herein by
  this reference.