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                      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, 1995.

   / / 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:  
                              (508) 388-4000
         
       Securities registered pursuant to Section 12(b) of the Act:
                                 
              Title of Class                    Exchange
       Common Stock, $2.50 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.  /X/

   The aggregate market value of the voting stock held by non-affiliates 
   on October 31, 1995 based upon the last sales price on that date was 
   approximately $40,367,000.

   DOCUMENTS INCORPORATED BY REFERENCE:  Part III hereofincorporates by 
   reference portions of the definitive Proxy Statement dated 
   December 5, 1995, for the Annual Meeting of Stockholders to be held 
   January 16, 1996.  Part IV hereofincorporates 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 1988, 
   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 and 
   Registrant's Quarterly Report on Form 10-Q for the Quarter ended 
    May 31, 1995.
 2
                        ESSEX COUNTY GAS COMPANY
  
                               FORM 10-K
  
                             Annual Report
  
                        Year Ended August 31, 1995
  
                        ---------------------------
  
                            Table of Contents
  
  Item No.                          Topic                   Page
  
                                PART I
  
  1.     Business                                              1
  2.     Properties                                           10 
  3.     Legal Proceedings                                    10
  4.     Submission of Matters to a Vote of Security Holders  10
  
                                PART II
  
  5.     Market for the Registrant's Common Equity and Related
         Stockholder Matters                                  11
  6.     Selected Financial Data                              11
  7.     Management's Discussion and Analysis of Financial
         Condition and Results of Operations                  13
  8.     Financial Statements and Supplementary Data          19
  9.     Changes in and Disagreements with Accountants on
         Accounting and Financial Disclosure                  36
  
                               PART III
  
  10.    Directors and Executive Officers of the Registrant   37
  11.    Executive Compensation                               37
  12.    Security Ownership of Certain Beneficial Owners and
         Management                                           37
  13.    Certain Relationships and Related Transactions       37
  
                               PART IV
  
         Signatures                                           38
  14.    Exhibits, Financial Statement Schedules and Reports
         on Form 8-K                                          47

                             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 and Newburyport, the towns of Amesbury and Ipswich, and thirteen 
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 fiscal 
1995 there was a slight increase in new residential construction.  New home 
construction activity significantly impacts the degree to which the Company 
is able to grow itscustomer base.
      

Sales and Customer Data

The Company sells natural gas to over 40,000 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 1995, 
the Company's total operating revenues were $45,049,573 of which 
approximately 63.9% was derived from residential customers, 29.5% from 
commercial and industrial customers, 4.3% from interruptible customers 
and 2.3% from other sources.  During this period, the Company sold 
5,951,055 thousand cubic feet of gas (Mcf), of which approximately 53.7% 
was purchased byresidential customers, 31.0% by commercial and industrial
customers and 15.3% by interruptible customers.  Losses and company use 
amounted to 86,387 Mcf for 1995.

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

                         Fiscal  Years  Ended  August 31,
                            1995       1994      1993        1992      1991
                                   (Dollars and Mcfs in Thousands)


Operating Revenues:                                     
Residential-general       $ 2,159   $  2,291  $ 2,160    $ 2,070     $ 2,107
Residential-heating        26,589     29,245   27,218     25,150      21,666
Commercial and Industrial  13,353     15,000   14,006     13,432      12,001
Interruptible               1,933        888      653      1,316       1,724
Other                       1,016      1,112      979        945         859
Total                     $45,050    $48,536  $45,016    $42,913     $38,357
                          =======    =======  =======    =======     =======

Gas Delivered (Mcf):
Residential-general           148        159      158        158         171
Residential-heating         3,045      3,325    3,228      3,083       2,651
Commercial and Industrial   1,843      2,014    1,948      1,927       1,730
Interruptible                 915        389      273        669         850
Total Sales                 5,951      5,887    5,607      5,837       5,402
Losses and Company Use         86         79       89        101          78
Total                       6,037      5,966    5,696      5,938       5,480
                           ======     ======   ======     ======      ======

Number of Customers at Year-End:
Residential-general         7,369      7,560    7,439      6,776       6,965
                            3,884      3,863    3,941
Interruptible                   2          2        2          2           2
Total                      40,524     39,616   38,759     38,163      38,076
                           ======     ======   ======     ======      ======

Effective Degree Days
(20-Year Average: 6,772)    6,258      7,012    6,956      6,750       5,843


The Company's residential customers are classified as either general or 
heating customers.  In fiscal 1995, residential-heating customers 
accounted for approximately 59.0% of total operating revenues, while 
residential-general customers accounted for approximately 4.8% of total
operating revenues.  Operating revenues from residential customers decreased 
approximately 8.8% to $28,747,790 in fiscal 1995 from $31,535,901 in fiscal 
1994.  The sales decrease was attributable to the relatively warmer winter in
fiscal 1995 compared to fiscal 1994 as residential volumes decreased 8.3%.  
The average rate charged to residential customers per Mcf of gas was $9.00 
and $9.05 in fiscal 1995 and 1994, respectively.  The decrease was primarily
attributable to lower gas costs incurred by the Company.

The Company's commercial and industrial firm revenues decreased 
approximately 10.9% to $13,353,053 in fiscal 1994 from $15,000,214 in 
fiscal 1994.  The decrease was attributable to a 8.5% volume decrease and 
a 2.7% decrease in the average price charged per Mcf of gas from $7.45 to
$7.25.  The sales decreases were largely attributable to warmer weather 
experienced during the winter in fiscal 1995 as compared to fiscal 1994.

The Company has two interruptible customers, only one of which purchased 
significant amounts of gas from the Company in fiscal 1995.  Total 
interruptible revenues in fiscal 1995 were $1,932,751 compared to $888,236 
in fiscal 1994.  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 directly to the Company's firm 
customers unless interruptible volumes exceed a certain threshold 
specified by the Massachusetts Department of Public Utilities ("MDPU").  
Once that threshold is attained, the Company may retain 10% of gross 
profits.  The threshold was not attained in fiscal 1995. Any gross profit 
returned to the customers are returned through a Standard Cost of Gas 
Adjustment ("SCGA") under which the Company is permitted to recover its 
gas costs. The average price charged by the Company to interruptible 
customers was $2.11 per Mcf and $2.28 per Mcf in 1995 and 1994, respectively.

The Company's largest customer purchases gas on an interruptible basis and 
accounted for approximately 2.5% of operating revenues on average over the 
past three fiscal years ended August 31, 1995.  Sales to that customer in 
1995 totaled $1,890,561 or 4.2% of total Company operating revenues.  Since 
most of the  gross profit earned on interruptible sales is returned to firm 
customers, the Company believes that the loss of any 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 2% of the total
operating revenues of the Company over the past three years ended 
August 31, 1995.

During 1995, the Company added 955 new customers.  In fiscal 1994 and 1993, 
net new customer additions (which approximated gross additions) were 857 
and 596, 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 single-day demand during the last five fiscal years was 
46,768 Mcf on February 6, 1995.  Maximum single-day demand for 1994 and 
1993 were 45,500 and 40,852 respectively.  The Company has the ability
to meet a single-day demand of approximately 65,000 Mcf.  Single-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 1995 was 6,037,442 Mcf compared to 5,965,627 Mcf in 1994 and
5,695,910 in fiscal 1993.

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

                      Fiscal Years Ended August 31,
                     1995      1994       1993      1992       1991

Gas Supply (Mcf):
  Natural gas                                     
   from pipeline  4,844,912  4,780,294  4,222,801  5,344,754  4,719,549
  Underground 
   storage 
   withdrawn        820,493    820,103  1,271,670    459,594    569,458
  Liquefied natural 
   gas produced     372,037    361,440    201,439    132,965    190,508
  Propane air 
   produced               -      3,791          -        206        288
  Total           6,037,442  5,965,628  5,695,910  5,937,519  5,479,803
                  =========  =========  =========  =========  =========


For the year ended August 31, 1995, approximately 80.2% 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 dekatherms ("DTH") (each DTH is approximately 
0.975 Mcf) 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 are subject to approval 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 each per day 
for nine years, 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 Mcf per day from Boundary 
and may purchase up to 587,650 Mcf per year, the annual quantity limitation
for the contract.  The Company began in January 1988 taking up to a maximum 
of 1,610 Mcf per day.  Pursuant to a supply contract with Boundary, the 
Company is required to purchase 75% 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 569,828 Mcf 
in fiscal 1995 or 97.0% 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 Mcf per 
day (approximately 2,051 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 717,193 Mcf per year (approximately 735,583 
DTH per year), the annual quantity limitation for the contract.  The 
contract requires the Company to purchase at least 60% 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 706,742 Mcf in fiscal 1995
or 98.5% of the contracted amount in fiscal year 1995.  The Company has firm 
transportation contracts with the Iroquois Pipeline and TGPC for the delivery 
of the above-mentioned volumes.

The Company has three contracts for underground storage with a total storage 
capacity of approximately 1,461,868 Mcf.  The Company used a total 
of 842,205 Mcf, including 21,712 Mcf of fuel gas, of its total underground 
storage in fiscal 1995.

Under a contract expiring November 1, 2000, the Company obtained 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 for underground storage with Consolidated 
Supply Corporation for a total volume of 359,450 DTH expiring April 1, 
2000.  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 3,268 DTH per day (approximately
3,186 Mcf per day) on a firm basis.

The Company's third contract for underground storage is with Penn-York 
Energy Corporation and extends through March 31, 1996.  It is expected 
that the contract will be renewed on an annual basis.  The total storage 
volume under this contract is 350,000 Mcf, and the maximum daily withdrawal 
is 3,182 Mcf.  The contract is backed by a transportation contract with 
TGCP which has been authorized by FERC to deliver to the Company 
approximately 787 Mcf per day from this storage facility on a firm basis and 
the balance on a "best efforts" basis.  If the need develops, the Company 
will seek a firm transportation contract with TGPC for delivery of the full 
volume under the contract with Penn-York Energy Corporation.

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 400,000 Mcf and has a 
daily sendout capacity of 30,000 Mcf.  In fiscal 1995, sendout of LNG
totaled 372,037 Mcf.  At the same location, the Company owns and operates 
a propane plant that has a storage capacity equivalent of approximately 
40,000 Mcf with a total daily sendout capacity of 7,000 Mcf.  In fiscal 
1995, there was no sendout of propane.  Due to the relatively high cost 
of LNG and propane, the Company uses these fuels primarily to
satisfy peak winter demand.

Under an agreement with Bay State Gas Company expiring October 31, 1996, 
the Company is required to purchase 50,000 Mcf of LNG during each summer 
period and approximately 110,000 Mcf during each winter period with an 
option to purchase an additional 37,000 Mcf during each winter period.

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 distri-
bution 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 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. Although 
it has no direct competition in its territory, 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 has received 
approval for these rates, to date no customer has selected this option.

While the current retail price of natural gas is 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 that the relative price differ-
ential between natural gas and oil will diminish 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, 1995, 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 four requests for rate increases and has 
been granted a total of $5,930,791 in rate relief by the MDPU, which 
amounts to 61.6% of the total requested.  The Company's most recent rate 
increase request was filed in fiscal 1993 and approved in fiscal 1994.  
The Company's fiscal 1993 rate increase request was for an annualized 
increase of approximately $3,000,000 and the MDPU approved an annualized 
rate increase of approximately $1,730,000.  The rate increase was 
effective December 1, 1993.

The MDPU permits Massachusetts gas companies to utilize a SCGA 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 
SCGA and no portion of the interruptible profits are retained by the 
Company unless certain volumes are sold. Supplemental fuel inventory and 
related administrative and carrying costs are also recovered through the SCGA.  
In addition, the MDPU allows recovery of the following through the SCGA:  
(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 SCGA.  The Company has also incurred costs 
associated with MDPU Energy Conservation Load Management programs and the 
Company expects to recover these costs through the SCGA.

Changes in rates charged to customers which are not incorporated in the SCGA
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 final 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 signifi-
cantly 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 SCGA.

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.

The Company, or its predecessors, previously operated four manufactured 
gas plants and one storage facility (collectively, "MGPs") at sites in 
Massachusetts.  Each of these facilities has been out of operation for 
more than 25 years.  It is possible that, during the manufacturing 
process, some or all of the MGPs may have discharged certain substances 
on the sites which may now be deemed 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 Massachusetts Department of Environmental Protection
("MDEP") are focusing 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 will be conducted in 1996 to determine the 
level of contamination and to assess whether any remediation is required.  
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 SCGA 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.  A 1990 MDPU agreement also provides for no further investigation 
of the prudency of any Massachusetts gas utility's past MGP operations.

In 1990, the Company received notification from the MDEP that the MDEP 
has reason to believe that the Company may be a potentially responsible 
party, along with several others, with respect to certain metal salvaging 
sites.  See Footnote I of the Company's Financial Statements.

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 (psi) and a length greater than one mile requires approval 
by the Energy Facilities Siting 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, 1995, the Company had 128 permanent employees, 76 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, 1995, the Company had approximately 
744 miles of gas mains and 37,124 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 40,000 Mcf.  In addition, the Company, through its wholly owned 
subsidiary, LNG Storage, Inc., owns an LNG storage facility with a 
storage capacity of 400,000 Mcf.

On August 31, 1995 the Company's gross utility plant amounted to 
$91,462,732 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 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 corporate headquarters building and distribution 
facilities.  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, 1996.

Item 3:  Legal Proceedings

There are certain non material routine 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.

                             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 31, 1995, the Common Stock was held by 1,383 
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, 1994                   
   First Quarter                  $30.50   $29.00        $0.37
   Second Quarter                  29.50    26.75         0.38
   Third Quarter                   28.00    24.75         0.38
   Fourth Quarter                  25.75    24.25         0.38
Fiscal Year Ended August 31, 1995
   First Quarter                   25.50    24.25         0.38
   Second Quarter                  25.25    23.50         0.39
   Third Quarter                   24.75    22.00         0.39
   Fourth Quarter                  25.50    22.50         0.39
Fiscal Year Ending August 31, 1996
   First Quarter
    (through November 10, 1995)    25.25    24.25         0.39*

*Paid on October 1, 1995 to shareholders of record on
 September 18, 1995.

The Company has paid regular dividends since 1914. Common Stock 
dividend payments in fiscal 1995 totaled $1.55 per share, as compared to 
$1.51 in fiscal 1994.  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, 1995.  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.

                      SELECTED CONSOLIDATED FINANCIAL DATA


                           Fiscal Years Ended August 31,

                             1995     1994      1993    1992     1991
         (000s omitted, except for per share and ratio information)


Income Statement Data:
                                                      
Operating revenues         $45,050   $48,536  $45,016   $42,913  $38,357
Operating income             5,909     5,794    5,766     5,243    4,741
Income available for 
 common stock                3,180     3,302    2,880     2,331    1,895
Shares of common stock 
 outstanding,
 weighted average            1,591     1,559    1,475     1,306    1,281
Earnings per common share    $2.00     $2.12    $1.95     $1.79    $1.48
Cash dividends declared
 per common share            $1.55     $1.51    $1.47     $1.43    $1.40
Ratio of earnings to fixed
 charges (1)                 2.54x     2.83x    2.45x     2.11x    1.86x

Balance Sheet Data:

Long-term debt (excluding
 current portion)         $20,689   $21,713  $22,148   $21,031  $23,011
Redeemable preferred 
 stock                        336       350      364       378      392
Common stock equity        30,709    28,870   26,985    20,982   19,782
Total capitalization      $51,734   $50,933  $49,497   $42,391  $43,185
                           ======    ======   ======    ======   ======
Capital lease (excluding
 current portion)         $   654   $   700  $   742   $   781  $   816
                           ======    ======   ======    ======   ======
Total assets              $86,582   $83,511  $76,535   $73,157  $65,737
                           ======    ======   ======    ======   ======

_______________________
(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 trust, 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
Fiscal Years Ended August 31, 1995 and 1994

Revenues

Using a twenty-year average, the Company's service territory incurs 
6,772 effective degree days in one year. Fiscal 1995 had 6,258 effective 
degree days compared to 7,012 in fiscal 1994.  As a result, the volume of 
sales to the Company's two major firm customer classes, residential heating 
and commercial and industrial, decreased by 8.4% from 5,497,235 Mcf in 1994 
to 5,036,056 Mcf in the current year.  The warmer weather, coupled with a 
1.2% decrease in price, resulted in revenues of $45,049,573 compared to
$48,536,005 in the prior year.  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).  Firm revenues  
in fiscal 1995 were 9.5% lower than in fiscal 1994.  The decrease was 
attributable to the weather and price factors discussed previously, as 
the Company's customer base increased by nearly 3.0%.  The average unit
price of gas sold to all customers, including interruptible customers, 
decreased 8.2% to $7.40 from $8.06 in fiscal 1994.  For firm customers, 
the average unit price decreased to $8.36 from $8.47 in the prior year.  
The Company's interruptible revenues increased 117.6% as interruptible
sales volumes increased 525,651 Mcf.  The increase in interruptible 
sales volumes and revenues was primarily a result of the Company's 
ability to purchase natural gas on a low cost spot market basis.  
If interruptible volumes exceed a threshold based on sales during the 
last four years, the Company may retain 10% of the gross profit on 
interruptible sales and refund the remaining 90% to the Company's firm
customers.  In fiscal 1995, the required volumes of interruptible sales 
were not obtained, and the Company returned all gross profit on 
interruptible sales to its firm customers.  Therefore, the increase in 
volumes did not significantly impact the Company's earnings.  Other 
revenues decreased slightly to $1,105,979 from $1,111,654 in fiscal
1994.

During fiscal 1995, the Company added 955 new customers. The Company's 
ability to attract customers has been assisted by the improving economy 
and resultant new construction. Although there was an unfavorable price 
comparison with oil, which is the Company's primary competition in the 
area of space heating, the environmental and convenience advantages
of natural gas allow the Company to compete on a favorable footing.

Operating Expenses

The Company's major operating expense is its cost of gas which decreased 
9.9% to $22,525,442 in fiscal 1995 from $25,000,794 in fiscal 1994.  
This decrease was primarily due to a decrease of 8.4% in firm volumes of 
gas sold.  These gas costs are recovered from the Company's firm customers
through a Standard Cost of Gas Adjustment ("SCGA") which is adjusted 
semi-annually to reflect any changes in gas costs.

Operations and maintenance expenses decreased 9.2% to $11,078,029 in 
fiscal 1995 from $12,206,720 in fiscal 1994. This decrease was mainly 
attributable to:  decreases of approximately $600,000 in outside 
services, $220,000 in medical expenses and $340,000 in uncollectible 
accounts. The reduction in outside services expense was primarily
related to the cost of one-time items such as actuarial services 
relating to employee benefits, including medical costs for current and 
future retirees; legal and other consulting services relating primarily 
to regulatory affairs such as interruptible and firm transportation 
rates; general comments on utility mergers and acquisitions; and other
regulatory items incurred in fiscal 1994.  The decrease in employee 
benefits was primarily related to reduced medical costs for current and 
future retirees as medical utilization decreased.

Utility Plant depreciation expense increased 6.8% to $2,500,585 in 
fiscal 1995 from $2,341,381 in fiscal 1994, reflecting the ongoing 
investment in upgrading and expanding the Company's distribution system.

Taxes, other than federal income, decreased 2.4% to $1,634,216 in fiscal 
1995 from $1,675,782 in fiscal 1994. This decrease was related to a 
decrease in state income taxes resulting from lower pre-tax earnings.

Federal income taxes decreased 7.6% to $1,401,858 in fiscal 1995 from 
$1,517,130 in fiscal 1994, also reflecting the decrease in the Company's 
pre-tax earnings.  The Company's combined effective tax rate for both 
federal and state income taxes was 34.6%.

Interest on long-term debt decreased 3.5% to $2,048,959 in fiscal 1995 
from $2,124,058 in fiscal 1994.  This decrease was related to the sinking 
fund payments of long-term debt.  Other interest expense increased 108.8% 
to $732,941 in fiscal 1995 from $351,088 in fiscal 1994.  This increase 
was primarily attributable to higher levels of short-term debt outstanding 
and higher interest rates in fiscal 1995 as compared to fiscal 1994.

Income available for common stock decreased 3.7% to $3,179,778, or $2.00 
per share, in fiscal 1995 from $3,301,711, or $2.12 per share, in fiscal 
1994.  Dividends per share declared and paid for fiscal 1995 and 1994 were
$1.55 and $1.51, respectively.

Fiscal Years Ended August 31, 1994 and 1993

Revenues

The Company experienced 7,012 effective degree days in fiscal 1994 
compared to only 6,956 in fiscal 1993.  As a result, the volume of unit 
sales in the Company's two major customer classes, residential heating 
and commercial and industrial, increased by 3.1% from 5,175,765 Mcf in 
1993 to 5,338,422 Mcf in the current year.  The colder than normal
weather, plus a 4.2% increase in rates approved by the DPU effective
December 1, 1991, resulted in increased revenues from $45,016,043 to 
$48,536,005.  Firm revenues increased nearly 7.3% over fiscal 1993, 
primarily due to the weather and rate factors indicated above, as the 
Company's customer base increased by only 2.2%.  The average unit price 
of all gas sold to customers, including interruptible customers, 
increased 2.7% to $8.06 from $7.85 in fiscal 1993.  For firm customers 
only, the average unit price increased to $8.47 from $8.13 in the prior 
year. The Company's interruptible revenues increased 36.0% as 
interruptible volumes increased 116,679 Mcf.  The increase in 
interruptible volumes was primarily due to the availability of natural 
gas at a more favorable price than oil.  The increase in volumes did not
significantly impact the Company's earnings due to the accounting 
treatment discussed above.  Other revenues increased slightly to 
$1,111,654 from $978,764 in 1993. 

Operating Expenses

The Company's major operating expense is its cost of gas, which 
increased 6.6% to $25,000,794 in fiscal 1994 from $23,456,542 in 
fiscal 1993.  This increase was due to additional volumes of gas sold.

Operations and maintenance expenses increased 10.0% to $12,206,720 in 
fiscal 1994 from $11,097,811 in fiscal 1993. This increase was mainly 
attributable to:  increases of approximately $500,000 in outside 
services, $250,000 in medical expenses, $120,000 in regulatory expenses, 
$105,000 in legal and consulting costs related to Order 636, and an
increase of approximately $60,000 related to additional volumes of LNG 
vaporized.  The additional outside service expense was primarily 
related to items such as actuarial services relating to employee 
benefits, including medical costs for current and future retirees; 
legal and other consulting services relating primarily to regulatory 
affairs such as interruptible and firm transportation rates; general
comments on utility mergers and acquisitions; and other regulatory items.  
The increase in employee benefits was primarily related to $600,000 
for additional medical costs for current and future retirees as the 
Company has commenced recognizing these expenses over a twenty-year 
period.  These costs were offset by a reduction of approximately $350,000
in medical expenses for current employees.

Utility Plant depreciation increased 7.6% to $2,341,381 in fiscal 1994 
from $2,175,693 in fiscal 1993, reflecting the increase in the Company's 
utility plant. 

Taxes, other than federal income, increased 38.7% to $1,675,782 in 
fiscal 1994 from $1,208,506 in fiscal 1993. This increase was due to an 
increase in real estate and property taxes associated with the Company's 
increased investment in utility plant and an increase in state income
taxes resulting from the increase in the Company's pre-tax earnings.

Federal income taxes increased 15.7% to $1,517,130 in fiscal 1994 from 
$1,311,456 in fiscal 1993, 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 35.8%.

Interest on long-term debt decreased 13.0% to $2,124,058 in fiscal 1994 
from $2,442,345 in fiscal 1993.  This decrease was related to the 
prepayment in 1993 of long-term debt.  Other interest expense increased 
74.5% to $351,088 in fiscal 1994 from $201,208 in fiscal 1993.  Other 
interest expense increased 74.5% to $351,088 in fiscal 1994 from
$201,208 in fiscal 1993.  This increase was primarily attributable to 
higher levels of short-term debt outstanding and higher interest rates 
in fiscal 1994 as compared to fiscal 1993.

Interest on long-term debt decreased 13.0% to $2,124,058 in fiscal 1994 
from $2,442,345 in fiscal 1993.  This decrease was related to the 
prepayment in 1993 of long-term debt.  Other interest expense increased 
74.5% to $351,088 in fiscal 1994 from $201,208 in fiscal 1993.  This 
increase was primarily attributable to higher levels of short-term debt
outstanding and higher interest rates in fiscal 1994 as compared to 
fiscal 1993.

Income available for common stock increased 14.6% to $3,301,711 or 
$2.12 per share in 1994, from $2,880,490 or $1.95 per share in 1993.  
Dividends per share declared and paid for fiscal 1994 and 1993 were 
$1.51 and $1.47, respectively.

Liquidity and Capital Resources

The Company periodically borrows from banks on an unsecured, short-term 
basis.  At August 31, 1995, the Company had $4,890,000 of outstanding 
notes payable under available lines of credit totaling $16,500,000 with 
five different banks.  In addition, for the sole purpose of financing 
the Supplemental Fuel Inventory, the Company has a $7,000,000 line of 
credit.  The Supplemental Fuel Inventory line of credit expired 
October 31, 1995 and the Company has a bridge loan in place until it 
receives Massachusetts Department of Public Utilities ("MDPU") approval 
for a new, long-term financing.  MDPU approval is expected in late fall
or early winter 1995.  Due to the seasonal nature of the Company's 
business, the Company customarily draws upon its credit lines since both 
sales and construction activity are affected by seasonal weather 
conditions.  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.

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.  Management
anticipates that these and other sources will remain available and 
continue to adequately serve the Company's needs.  During fiscal 1995, 
the Company's construction expenditures were approximately $7,000,000.  
This compares to $6,100,000 in fiscal 1994.  These capital expenditures
were funded primarily from short-term debt and operations. The Company's 
higher construction expenditures in fiscal 1995 were primarily 
attributable to additional construction requirements to bring on new 
customers and major upgrading of the Company's existing infrastructure.  
Capital expenditures for fiscal 1996 are expected to be approximately 
$7,000,000.

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 SCGA which, subject to approval by the MDPU, permits the 
Company to change rates to recover its gas costs and certain other
costs on a dollar-for-dollar basis.  The SCGA is also used as the 
mechanism to reduce charges to firm customers by the margin earned on 
sales to interruptible customers.

The Company, or its predecessors, previously operated four manufactured 
gas plants and one storage facility (collectively, "MGPs") at sites in 
Massachusetts.  Each of these facilities has been out of operation for 
more than 25 years.  It is possible that, during the manufacturing
process, some or all of the MGPs may have discharged certain substances 
on the sites which may now be deemed 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 Massachusetts Department of Environmental Protection
("MDEP") are focusing 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 investi-
gation 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 will be conducted in 1996 to determine the level of 
contamination and to assess whether any remediation is required.  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 SCGA 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 MDPU agreement also provides for no further investigation 
of 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 
Federal Energy Regulatory Commission ("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, Tennessee 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.  Tennessee 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 $900,000 and is based
upon FERC approved filings.  This estimated liability has been included 
in the Company's financial statements at August 31, 1995, together with 
the related regulatory asset.  The MDPU has approved the recovery of GSR 
costs from all firm customers.

The MDPU had previously sought comments from interested persons on how 
incentive regulation could improve upon the existing framework of utility 
regulation.  As a result, as part of any general rate filing, companies 
must provide the MDPU with recommendations.

               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, 1995
and 1994, and the related consolidated statements of income,
retained earnings and cash flows for each of the three years
in the period ended August 31, 1995.  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, 1995 and 1994, and the results of its operations
and its cash flows for each of the three years in the period
ended August 31, 1995, in conformity with generally accepted
accounting principles.



ARTHUR ANDERSEN LLP
Boston, Massachusetts,
October 30, 1995


Item 8:  Financial Statements and Supplementary Data

                          CONSOLIDATED STATEMENTS OF INCOME
                           Fiscal Years Ended August 31,

                                  1995           1994            1993

Operating revenues                                      
                               $45,049,573    $48,536,005    $45,016,043
Less:  Cost of gas              22,525,442     25,000,794     23,456,542
Operating margin                22,524,131     23,535,211     21,559,501
Operating expenses:              
Operations and 
 maintenance expenses           11,078,029     12,206,720     11,097,811
  Depreciation                   2,500,585      2,341,381      2,175,693
  Taxes, other than federal 
   income                        1,634,216      1,675,782      1,208,506
  Federal income taxes           1,401,858      1,517,130      1,311,456
     Total operating expenses   16,614,688     17,741,013     15,793,466

Operating income
                                 5,909,443      5,794,198      5,766,035
Other income (expense), net          6,202         (7,828)      (184,152)
Income before interest charges   5,915,645      5,786,370      5,581,883

Interest charges:
  Interest on long-term debt     2,048,959      2,124,058      2,442,345
  Amortization of deferred 
   debt expense                     27,081         26,697         84,323
  Other interest expense           732,941        351,088        201,208
  Allowance for funds used
    during construction            (92,428)       (37,268)       (47,337)
     Total interest charges      2,716,553      2,464,575      2,680,539

Net income                       3,199,092      3,321,795        901,344
Annual redeemable
 preferred dividend requirements   (19,314)       (20,084)       (20,854)
Income available for 
 common stock                   $3,179,778    $ 3,301,711    $ 2,880,490
                                ==========    ===========    ===========
Shares of common stock outstanding
(weighted average)               1,591,372      1,558,574      1,475,313
Earnings per common share           $ 2.00         $ 2.12         $ 1.95
Cash dividends declared 
 per common share                   $ 1.55         $ 1.51         $ 1.47



            CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                      Fiscal Years Ended August 31,
                                    1995          1994           1993

Balance at beginning of year   $11,857,299    $10,903,703    $10,198,858
Net income                       3,199,092      3,321,795      2,901,344
     Total                      15,056,391     14,225,498     13,100,202

Cash dividends declared:
  Redeemable preferred stock        19,314         20,084         20,854
  Common stock                   2,460,382      2,348,115      2,175,645
     Total                       2,479,696      2,368,199      2,196,499

Balance at end of year         $12,576,695    $11,857,299    $10,903,703
                               ===========    ===========    ===========
<FN>
The  accompanying  notes  are an  integral  part  of  these consolidated 
financial statements.

        
             CONSOLIDATED BALANCE SHEETS


ASSETS

                                         August 31,        August 31,
                                            1995           1994
                                                     
Utility plant, at cost                  $ 91,462,732     $ 85,564,414
Less:  Accumulated depreciation           20,304,386       18,519,429
  Net utility plant                       71,158,346       67,044,985
Other property and investments               570,620          499,439
Capitalized lease (net of accumulated 
 amortization of$423,806 in 1995 and 
  $381,858 in 1994)                          699,991          741,939
                                                
Current assets:
  Cash and cash equivalents                  136,925          130,939
  Accounts receivable:
     Customers (net of allowance for 
     uncollectible accounts of $595,000 
     in 1995 and $804,000 in 1994)         1,418,510        1,629,383
     Other                                   280,889          407,523
  Income tax refunds receivable              200,000          688,000
  Supplemental fuel inventory              6,477,155        6,783,404
  Materials and supplies (at average cost)   594,817          583,422
  Prepaid deferred income taxes            1,397,422          816,445
  Prepayments and other                      350,660          316,738
     Total current assets                 10,856,378       11,355,854
                                                
Deferred charges:
  Unamortized debt expense and other       1,028,319        1,231,689
  Regulatory assets                        2,267,954        2,636,658
     Total deferred charges                3,296,273        3,868,347
                                        $ 86,581,608     $ 83,510,564
                                        ============     ==========
                                                              
<FN> 
The  accompanying  notes  are an  integral  part  of  these consolidated 
financial statements.

                     CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

                                  August 31,    August 31,
                                              1995          1994
                                                    
Common stock equity                        $30,709,276   $28,870,444
Redeemable preferred stock                     336,000       350,000
Long-term debt, less current portion        20,689,366    21,713,124
    Total capitalization                    51,734,642    50,933,568
Noncurrent obligations under capital lease     654,390       699,991

Current liabilities:
 Current portion of long-term debt             978,758     1,035,304
 Current obligation under capital lease         45,599        41,948
 Obligations under supplemental fuel 
  inventory trust                            5,131,153     6,428,770
 Notes payable, banks                        4,890,000     4,500,000
 Accounts payable                            2,986,307     2,930,578
 Accrued interest                              825,322       625,784
 Refundable gas costs                        2,490,178       770,184
 Accrued transition costs                      858,715     1,018,531
 Supplier refund due customers               2,454,739     1,661,812
 Other                                         850,404       852,259
       Total current liabilities            21,511,175    19,865,170
Commitments and contingencies
Deferred credits:
 Accumulated deferred income taxes           9,092,349     8,452,562
 Unamortized investment tax credit           1,280,680     1,350,779
 Deferred directors' fees                      879,009       777,871
 Other                                       1,429,363     1,430,623
       Total deferred credits               12,681,401    12,011,835
                                           $86,581,608   $83,510,564
                                           ===========   ===========
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.


                  CONSOLIDATED STATEMENTS OF CASH FLOWS

                              Fiscal Years Ended August 31,
                                    1995        1994        1993
Operating activities:                                    
 Net income                        $ 3,199,092  $ 3,321,795  $ 2,901,344
 Adjustments to reconcile net 
  income to net cash:
  Depreciation, including amounts 
   related to non-utility operations 2,920,476    2,754,465    2,589,867
  Provisions for uncollectible 
   accounts                           (208,797)     761,385      741,431
  Deferred income taxes                 40,876    1,006,618      706,519
  Amortization                           8,390        7,305       96,032
  Noncash compensation associated 
   with ESOP                           225,000      150,000      150,000
 Cash (used in) provided by working capital:
  Decrease (increase) in 
   accounts receivable                 546,304     (912,662)    (430,151)
  Decrease (increase) in inventories 
   including fuel                      294,854     (462,827)     777,064
  Decrease (increase) in prepayments 
   and other                           (33,922)     185,674       58,740
  Increase in accounts payable          55,729      104,406      167,653
  Increase in supplier refund 
   obligations                         792,927    1,661,812            -
  (Increase) decrease in taxes 
   payable/receivable                  488,000     (374,323)    (313,677)
  (Decrease) increase in recoverable
    (refundable) gas costs           1,719,994     (154,584)     (84,886)
  Other, net                           658,391     (837,888)     273,654
    Total adjustments                7,508,222    3,889,381    4,732,246
       Net cash provided by operating 
        activities                  10,707,314    7,211,176    7,633,590
Investing activities:
 Utility capital expenditures       (6,967,340)  (6,131,471)  (6,671,526)
 Payments for retirements of property,
  plant and equipment, net             (66,497)    (183,999)     (78,401)
       Net cash used in investing 
        activities                  (7,033,837)  (6,315,470)  (6,749,927)
Financing activities:
 Dividends paid                     (2,479,696)  (2,368,199)  (2,196,499)
 Issuance of common stock              814,126      730,874    5,106,677
 Issuance of long-term debt                  -            -    4,661,445
 Retirements of preferred stock        (14,000)     (14,000)     (14,000)
 Principal retired on long-term debt  (855,304)    (193,340)  (4,219,742)
 (Decrease) increase in supplemental 
  fuel inventory trust              (1,297,617)     862,068   (1,278,003)
 (Decrease) increase in notes 
  payable, banks                       390,000      300,000   (3,250,000)
 Payment of ESOP debt                 (225,000)    (150,000)    (150,000)
       Net cash used in financing 
        activities                  (3,667,491)    (832,597)  (1,340,122)
Net (decrease) increase in cash 
 and cash equivalents                    5,986       63,109     (456,459)
Cash and cash equivalents at 
 beginning of year                     130,939       67,830      524,289
Cash and cash equivalents at 
 end of year                       $   136,925  $   130,939 $     67,830
                                   ===========  =========== =============
                                   
                                   Supplemental disclosures:
 Cash paid during the year for:
  Interest (net of amount 
   capitalized)                    $ 2,517,015  $ 2,449,138  $ 2,650,475
                                   ============  =========== ============
  Income taxes                     $ 1,743,197  $ 1,196,360  $ 1,305,394
                                   ============ ============ ============
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.                                             

               CONSOLIDATED STATEMENTS OF CAPITALIZATION
             

                                      August 31,  August 31,
                                               1995        1994
Common stock equity:
 Common stock, $2.50 par value, 
  5,000,000 authorized shares
 Issued and outstanding, 
 1,607,061 at August 31, 1995                               
 and 1,572,062 at August 31, 1994             $ 4,017,653   $  3,930,155
 Additional paid-in capital                    14,311,026     13,532,990
 Unrealized gain on investments 
  available for sale, net                          28,902              -
 Retained earnings                             12,576,695     11,857,299
                                               30,934,276     29,320,444
 Less:  Shares held by ESOP purchased 
  with debt                                       225,000        450,000
   Total common stock equity                   30,709,276     28,870,444

Redeemable preferred stock:
 5.50% series, $100 par value, 7,000 authorized shares
 Outstanding, 3,360 at August 31, 1995
    and 3,500 at August 31, 1994                  336,000        350,000

Long-term debt:
First Mortgage Bonds:
 10 1/4%, due serially from 1994 to 2003         5,400,000     6,000,000
 10.10%, due serially from 2010 to 2020          8,000,000     8,000,000
                                                13,400,000    14,000,000
Mortgage Note:
 8 1/2%, due serially from 1976 to 1997            838,124     1,048,428
Debentures:
 8 5/8%, due 2006                                2,245,000     2,250,000
 8.15%, due 2017                                 4,960,000     5,000,000
                                                 7,205,000     7,250,000
ESOP Loan Guarantee:
 7.0% due serially from 1987 to 1996               225,000       450,000
   Total debt                                   21,668,124    22,748,428
 Less:  Current portion maturing and payable       978,758     1,035,304
 Total long-term debt                           20,689,366    21,713,124
 Total capitalization                         $ 51,734,642  $ 50,933,568
                                              ============= ============
 <FN>
The accompanying notes are an integral part of these consolidated
financial statements.

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. 71, "Accounting for Certain Types of 
Regulation ("SFAS 71"). Under SFAS 71, a utility is allowed to defer 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, 1995, principal regulatory assets include 
(1) approximately $860,000 for transition costs associated with FERC 
Order 636, (2) $520,000 related to a settlement payment for a supplemental 
retirement plan, and (3) $425,000 related to deferred income taxes.  
Included in deferred credits is a regulatory liability of $794,000 related 
to deferred income taxes.

Statement of Financial Accounting Standards No. 121, "Accounting for the 
Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of" 
("SFAS 121") was issued in March 1995 and is effective for the Company 
on September 1, 1996.  SFAS 121 established accounting standards for the
impairment of long lived assets.  It requires that regulatory assets 
which are no longer probable of being recovered be written off.  Based 
upon the current regulatory environment in the Company's service 
territory, it is not expected that the adoption of SFAS 121 will have a 
material impact on the Company's financial position or results of
operations.

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 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 3.03% for fiscal 1995, 1994, and 1993. 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. 

Reclassifications

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


B.  Supplemental Fuel Inventory Trust

The Company, with MDPU approval, finances its supplemental gas inventory 
through a single purpose trust which purchases gas with funds loaned to 
the trust by a bank. As required, the Company repurchases gas from the
trust at prices based on original product cost, financing and trust fees. 
The credit agreement between the trust and the bank provides for a total 
commitment of up to $7,000,000.  Financing and trust fees resulted in an
effective interest cost to the Company of 5.9% for 1995 and 4.6% in 1994 
based on average borrowing.  Upon termination of the plan by either party, 
the Company is obligated to reimburse the trust in an amount equal to the 
investment in the trust not previously reimbursed plus any other 
obligations incurred by the trust.  The Company has 240 days (60 days in 
the event of default) to reimburse the trust upon termination.

C.   Common Stock

Common stock activity for the three-year period ended August 31, 1995, 
is as follows:

              
                                                         Additional
                                Number of     Common       Paid-in
                                  Shares       Stock       Capital


Balance, August 31, 1992        1,317,805   $3,294,513   $ 8,238,964
 Dividend reinvestment plan        15,042       37,605       321,702
 Amortization of capital
   stock expense                      ---          ---        40,709
 Various employee stock plans       7,564       18,910       165,627
 Sale of common stock             203,634      509,085     4,053,748


Balance, August 31, 1993        1,544,045    3,860,113    12,820,750
 Dividend reinvestment plan        15,452       38,631       359,647
 Amortization of capital
   stock expense                        -            -        51,408
 Various employee stock plans      10,397       25,991       247,775
 Sale of common stock               2,168        5,420        53,410


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
 Various 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
                                ==========  ==========   ===========





D.  Redeemable Preferred Stock and Restriction on Retained
    Earnings

The preferred stock is currently redeemable, in whole or in part, at  
the option of the Company, by a payment to the holder of $100 per share  
plus accrued dividends in the event of involuntary liquidation.  This 
payment requirement increases fifty cents per share plus accrued dividends 
in the event of voluntary liquidation.

A purchase agreement provides that the Company will annually offer to 
purchase and retire up to, but not in excess of, 140 shares of redeemable 
preferred stock at $100 per share plus accrued dividends.  Payment of 
dividends on, or acquisition of, common stock is prohibited if the Company
fails to cumulatively offer to purchase 280 shares of preferred stock.  
Required offers were made, and the Company redeemed, 140 shares during 
each of the three fiscal years ending August 31, 1995.

Dividends on redeemable preferred stock are at a stated rate of 5.50% 
cumulative, payable quarterly January 1, April 1, July 1 and October 1.

Under the terms of the indenture securing the First Mortgage Bonds, 
retained earnings in the amount of $5,192,475 as of August 31, 1995, 
were unrestricted as to the payment of cash dividends on common stock and 
the purchase, redemption or retirement of shares of capital stock.

E.  Interim Financing and Long-term Debt

The Company periodically borrows from banks on an unsecured, short-term 
basis.  At August 31, 1995, the Company had $4,890,000 of outstanding 
notes payable with a weighted average interest rate of 6.4% under 
available lines of credit totaling $16,500,000.  The annual commitment 
fees related to these lines of credit are between 1/4% and 3/8%
on the total amount of the line.

Substantially all plant assets are pledged as collateral under the terms 
of the indenture of First Mortgage Bonds. The 8-1/2% Mortgage Note represents
an obligation secured by the liquified 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 $978,758 in 1996, 
$923,830 in 1997, $960,536 in 1998, $600,000 in 1999, $600,000 in 2000 and 
$17,605,000 thereafter.

F.  Income Taxes

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



                                      1995       1994         1993
Federal

 Current                         $1,469,957  $  796,930    $1,054,220
 Deferred                             2,000     791,000       330,000
 Amortization of investment
   tax credit                       (70,099)    (70,800)     (72,764)

                                  1,401,858   1,517,130    1,311,456
State
 Current                            292,615     173,459      213,603
 Deferred                               445     162,000       67,000

                                    293,060     335,459      280,603
Total income taxes               $1,694,918  $1,852,589   $1,592,059
                                 ==========  ===========  ===========


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:

                                   1995        1994         1993

Federal statutory rate               34.0%        34.0%        34.0%
                                    ======        ======       ======
Federal income tax
 expense at statutory rates      $1,663,963   $1,759,260   $1,527,756

Increase (decrease) in taxes resulting
 from:
     Amortization of investment
        tax credit                  (70,099)     (70,800)    (72,764)

     State taxes, net of
        federal benefit             199,980     221,403      185,596
     Other                          (98,926)    (57,274)     (48,529)

Total income tax expense         $1,694,918  $1,852,589   $1,592,059
                                 =========== ===========  ===========
Effective income
 tax rate                             34.6%       35.8%        35.4%
                                      ======      ======       ======

Effective September 1, 1993, the Company adopted the provisions of 
Statement of Financial Accounting Standards No. 109, "Accounting for 
Income Taxes" ("SFAS 109").  The adoption of SFAS 109 had no earnings 
impact on the Company. SFAS 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 
$425,000 was established for the recovery of deficiencies in deferred 
taxes as a result of the net effect of establishing some deferred taxes 
for temporary differences using the flow-through method. Recovery of this 
amount will be addressed in the Company's next rate filing with the MDPU.  
A regulatory liability of $794,000 was established for the tax benefit of 
unamortized investment tax credits, which SFAS 109 requires to be
treated as a temporary difference.  This benefit will be 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, 1995 and 1994 are as follows:

                                                  1995         1994
Liabilities
   Utility Plant-primarily depreciation      $ 9,957,069   $ 9,237,890
   Other                                         332,912       425,099
                                              10,289,981     9,662,989
Assets
   Investment tax credits                        794,403       827,152
Other                                          1,800,651     1,199,720
                                               2,595,054     2,026,872
Accumulated deferred income taxes, net       $ 7,694,927   $ 7,636,117
                                             ===========   ===========

The net year-end deferred income tax liabilities above are net of current  
deferred  tax  assets  of  $1,397,422  and $816,445, respectively, which 
is included in prepaid  income taxes in the accompanying Consolidated 
Balance Sheets.

Deferred federal income tax expense results from differences in  the  
timing of recognition of certain items for tax  and financial statement     
purposes.  The  components of the deferred income tax provision are as     
follows:

                                      1995        1994         1993

   Excess tax depreciation
     over book depreciation      $ 593,030     $575,050     $459,099
   Uncollectible accounts           70,990      (48,535)     (52,768)
   Rate case expenses              (40,939)     (48,813)      56,145
   Gas adjustment factor          (584,798)      52,558       28,862
   Other deferred charges
     and credits                   (63,865)     282,763      (52,817)
   Unbilled revenues                33,890      (25,033)      26,798
   Deferred state taxes                  -      (55,080)     (22,780)
   Medical insurance reserves        4,925            -      (62,458)
   Other                           (11,233)      58,090      (50,081)

   Deferred federal
     income taxes                $   2,000     $791,000     $330,000
                                 ==========    =========    =========

The tax effect of the cumulative amount of timing differences at 
August 31, 1995 for which deferred federal income taxes have not been 
provided is not significant.

G.  Leases

The Company is obligated under various lease agreements for certain 
facilities and equipment used in operations. Total expenditures under 
operating leases for each period were $289,721 in 1995, $309,992 in 
1994, and $287,736 in 1993.  A summary of property classified as 
capital leases as of August 31, 1995 and 1994 is as follows:

                                       1995             1994

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

   Less:  Accumulated depreciation    423,806          381,858

                                   $  699,991       $  741,939
                                   ==========       ==========

In accordance with the rate treatment allowed by the MDPU, the 
depreciation expense of $41,948, $38,540 and $35,500, along with 
interest of $60,502, $63,910 and $67,000 related to the capital lease, 
is included in other operating expenses for the years ended August 31, 
1995 and 1994 and 1993, 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-cancellable leases is as follows:

                              Capital Leases Operating Leases

   1996                           $102,500         $297,599
   1997                            102,500          254,357
   1998                            102,500          184,384
   1999                            102,500           26,644
   2000                            102,500            3,387
   Thereafter                      529,584            3,543
                                 1,042,084
   Total minimum lease payments                    $769,914
                                                   ========
   Less:  Amount representing
          interest                  342,093

                                   $699,991
                                   ========

H.  Employee Benefits

Pension Plans

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

Net pension cost for 1995, 1994 and 1993 consist of the following components:

                                       1995        1994        1993

   Service cost -- benefits
      earned during the year        $231,741    $212,190   $ 175,000
   Interest cost on projected
      benefit obligations            668,107     617,749     568,000
   Actual return on plan assets     (887,022)    (74,969)   (933,000)
   Net amortization and deferral     412,504    (444,131)    476,000

        Net pension cost            $425,330    $310,839    $286,000
                                    =========   =========   =========


The expected long-term rate of return on assets was 8.5% in 1995  
and 1994, the discount rate used in determining the actuarial present 
value of the projected obligation was 8.0% in 1995 and 1994 and the 
expected rate of pay increase was 6.0% in 1995 and 1994.

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,  1995 and 1994:

                                               1995              1994
     
Actuarial present value of benefit
obligations (in thousands)
Vested benefit obligation                       $ 7,960        $ 7,476
                                                ========       ========
Accumulated benefit obligation                  $ 8,433        $ 7,884
                                                ========       ========
Projected benefit obligation
for service rendered to date                    $ 9,329        $ 8,634
Plan assets, primarily listed stocks,
corporate bonds and U.S. bonds,
at fair value                                     8,034          7,467

Projected benefit obligation in excess
of plan assets                                   (1,295)        (1,167)
Unrecognized net gain                              (321)          (437)
Unrecognized prior service cost                   1,537          1,633
Adjustment required to recognize
additional minimum liability                       (330)          (465)
Unrecognized net obligation at transition            10             20

Net pension liability                            $  399       $    416
                                                 ========      ========

Assets in the pension plan are currently held in listed stocks,
corporate bonds and government bonds.

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 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 is payable in 10 equal 
annual installments of $150,000 through October, 1996.  The ESOP is 
recorded as a liability and the offsetting debit is accounted for as a
reduction of common stock equity in the accompanying consolidated balance 
sheets.  Interest is payable monthly at a floating rate which is 80% of 
the current prime rate.  The charge to income, which equals the Company's 
contribution, for 1995 was $141,359, for 1994 was $223,349, and for 1993
was $152,949.  Interest on ESOP debt was $17,365 for 1995, $37,023 for 
1994, and $51,758 for 1993.  Dividends on unallocated ESOP shares used 
to pay debt service for all periods presented was $27,193 for 1995, 
$41,352 for 1994, and $52,439 for 1993.

Savings Plan

The Company has a thrift savings plan in which the Company matches a 
portion of employee contributions up to six percent of a participant's 
wages. The Company contributed approximately $118,939 to the plan in 1995,
$108,000 to the plan in 1994, and $63,500 in 1993.

Postretirement Benefits Other Than Pension

On September 1, 1993, the Company adopted 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.  The cumulative effect of the implementation of 
SFAS 106 as of September 1, 1994 is being amortized over 20 years.  
Prior to 1994, the cost of postretirement benefits was recognized on a 
pay-as-you-go basis.  The cost of retiree medical and life insurance
benefits under the traditional pay-as-you-go basis was $223,000 for 1993. 
The Company is currently recovering the full SFAS 106 cost in rates.

The net periodic postretirement benefit cost for the year ended 
August 31, 1995 and 1994 were as follows:

                                            1995        1994

   Service cost                           $ 84,550    $110,691
   Interest cost                           284,861     296,310
   Loss on plan assets                      13,066           -
   Net amortization and deferral           157,634     203,868
       Total postretirement benefit cost  $540,111    $610,869
                                           ========   =========
  The funded status of the Company's postretirement benefit plan  using 
  a measurement date of July 1, 1995 and 1994, is as follows:

                                            1995        1994
   Accumulated postretirement
    benefit obligation:
       Retirees                        $(2,972,713)    $(2,714,112)
       Fully eligible active 
        Plan participants                 (118,200)       (168,942)
       Other active Plan participants   (1,264,135)     (1,183,982)
                                        (4,355,048)     (4,067,036)
   Plan assets at fair value               557,939         229,781
   Accumulated postretirement obligation
    greater than Plan assets            (3,797,109)     (3,837,255)
   Unrecognized transition obligation    3,669,616       3,873,484
   Unrecognized (gain) loss                 (3,021)       (141,261)
            Accrued postretirement
             benefit cost              $  (130,514)     $ (105,032)
                                       ============     ===========

The weighted average discount rate used in determining the accumulated  
postretirement benefit obligation was  7.5%  in 1995  and 1994.  
The annual increase in the cost of  covered health  care  benefits for  
1995  was  9.5%  and  7.5%  for participants under age 65 and over age 
65, respectively, and for  1994 was 13% and 8% for participants under 65 
and over 65, respectively.  This increase gradually decreases to  5%
in  the  year  2007 and thereafter.  A 1%  increase  in  the assumed 
health care cost trend would have increased the cost computed  under  
SFAS  106  by  $27,444  and  increased  the accumulated postretirement 
benefit by $309,465 as of  August 31, 1995.

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  1995  and  1994  totaling  $514,629  and
$506,000, 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.

Incentive Stock Option Plan

In 1995 the Company adopted a Stock Option Plan ("Plan").  In  accordance  
with the Plan, options may be  granted  from time  to time but the total 
number of shares subject to  the Plan  shall  not  exceed 100,000 with 
not more  than  25,000 shares  granted during any one year to any 
individual.   The Plan  is  considered an Incentive Stock  Option  Plan  
under Internal Revenue Code Section 422.  During 1995, a total  of 24,000  
shares  were  granted at  a  price  of  $24.50  with exercise  dates  
beginning  February  9,  1996  and   ending February  9, 2000.  
No options were exercised during  fiscal 1995.

In October 1995, the Financial Accounting Standards Board issued Statement 
of Financial Accounting Standards No.  123, "Accounting for Stock Based 
Compensation" ("SFAS 123").  The Company  will  be required to adopt this 
standard  effective September 1, 1996.  SFAS 123 establishes a fair value  
based method  of  accounting for stock based  compensation  plans. SFAS 123  
allows  companies to either measure  compensation using  the  fair value 
method or to continue  to  apply  the provisions  of  APB  Opinion No. 23, 
"Accounting  for  Stock Issued to Employees" and include footnote 
disclosure of  pro forma net income and earnings per share calculated as if 
the fair value method had been applied.  The Company expects  to adopt the 
latter method and concludes that the adoption  of this standard will not 
have a material impact on the results of operations or its financial 
condition.

I. 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 1996 
and approximately $6,000,000 in each of the four following 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:

                                                 1996 to 2000

Pipeline Transportation Demand                    $5,182,643

Underground Storage Demand                           979,608

Underground Storage Transportation                 1,004,011

Pipeline Gas Inventory Charge                      1,662,951

GSR Charges                                          858,715
                                                  $9,687,928
                                                  ===========

FERC Order 636 also allows the pipeline companies to recover transition 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, 1995, 
the transition costs are estimated at $860,000 and will be billed over a 
period of approximately three years 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.

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.  Each of these facilities has been out of operation for 
more than 25 years.  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 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 
will be conducted in 1996 to determine the level of contamination and to 
assess whether any remediation is required.  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 SCGA 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 MDPU agreement also 
provides for no further investigation of the prudency of any Massachusetts 
gas utility's past MGP operations.

Subsequent Events

On September 15, 1995 the MDPU approved the Company's petition to change 
the par value of the Company's common stock from $2.50 par value to no par 
value.  The change was effective October 5, 1995.

The Company has petitioned the MDPU for a new supplemental fuel agreement 
replacing the one that expired October 31, 1995.  Financing from the 
expiration of the original arrangement to approval from the MDPU has been
accomplished by a $7,000,000 floating rate bridge loan which expires 
December 31, 1995.  The Company expects MDPU approval for the supplemental 
fuel agreement in December 1995.

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 5, 1995, for the Annual Meeting of Stockholders to be held on 
January 16, 1996.


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 5, 1995, for the Annual Meeting of Stockholders to be held on 
January 16, 1996. 
                  
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 5, 1995, for the Annual Meeting of Stockholders to be held on 
January 16, 1996. 


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 5, 1995, for 
the Annual Meeting of Stockholders to be held on January 16, 1996.


                            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   , 1995      

by 
          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    11/28/95


/s/ Philip H. Reardon       President and Chief      11/28/95
                            Executive Officer

/s/ James H. Hastings       Vice President and       11/28/95
                            Treasurer (Principal
                            Financial and Accounting
                            Officer)

/s/ Benjamin C. Bixby       Director                  11/28/95

/s/ Daniel A. Burkhard      Director                  11/28/95

/s/ Edward J. Curtis        Director                  11/28/95

/s/ Dorothy J. Dotson       Director                  11/28/95

/s/ Richard P. Hamel        Director                  11/28/95

/s/ Robert S. Jackson       Director                  11/28/95

/s/ Eric H. Jostrom         Director                  11/28/95
                                                              
/s/ Robert L. Meade         Director                  11/28/95

/s/ Kenneth L. Paul         Director                  11/28/95

/s/ Richard L. Wellman      Director                  11/28/95


                             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
          20 through 36, and the Report of Arthur Andersen LLP on page 19
          herein.

    2.    Schedules.

          None.

    3.    Exhibits

                                                        
Exhibit                                                
Number      Description                               

3.1        Restated Articles of Organization of Essex County
           Gas Company.3

3.2        Bylaws of Essex County Gas Company.4

4.1        The rights of holders of Redeemable Preferred
           Stock, 5.50% Series and the rights of holders of
           Common Stock, are defined in the Bylaws and the
           Restated Articles of Organization of the Registrant.
           See Exhibit 3.1.

4.2        Indenture dated as of June 1, 1986 between the Com-
           pany and Centerre Trust Company of St. Louis, Trustee.2

                                                       
Exhibit                                                
Number      Description                                

4.3        Eleventh Supplemental Indenture dated as of Septem-
           ber 15, 1988, providing for a 10 1/4% Series due
           2003.1

4.4        Twelfth Supplemental Indenture dated as of
           December 1, 1990, providing for a 10.10%
           Series due 2020.4

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

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, among
           Allstate Life Insurance Company of New York, and
           Essex County Gas Company.4

10.11      Iroquois Gas Transmission System, L.P. Gas Transpor-
           tation Contract for Firm Reserved Service dated
           February 7, 1991.3
             
                                                       
Exhibit                                                
Number      Description                                

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 Con-
           tract (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      The Company has entered into an amended employment
           contract with Charles E. Billups, Chairman of the
           Board.2*

10.19      Form of employment contract 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 sub-
           mitted with the Annual Report for each with the
           exception of compensation amounts.2*

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

10.22      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

10.23      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

10.24      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

                                                    
Exhibit                                                
Number      Description                                


10.25      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

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

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

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

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

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

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

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

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

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, 1995.

*Denotes Management Contract.

1    Previously 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.

2    Previously 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.

3    Previously filed as an exhibit to Registrant's 10-K filed for
     the fiscal year ended August 31, 1988, and is incorporated herein by 
     this reference.

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

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

6    Previously 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.

7    Previously 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.

8    Previously 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.



[CIK]                                            0000046189
[NAME]                             ESSEX COUNTY GAS COMPANY
[MULTIPLIER]                                          1,000

                                                   
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