<PAGE> 1
                            FORM 10-K
                                
               SECURITIES AND EXCHANGE COMMISSION
                     Washington, D.C.  20549
                                
        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
               THE SECURITIES EXCHANGE ACT OF 1934
                                
          For the Fiscal Year Ended September 30, 1996
                 Commission File Number  1-1141
                                
                        ENERGYNORTH,INC.
     (Exact name of registrant as specified in its charter)
                                
New Hampshire                              02-0363755
(State or other jurisdiction of            (I.R.S. Employer
incorporation or organization)             Identification No.)
                                
1260 Elm Street, P.O. Box 329, Manchester, New Hampshire 03105  (603-625-4000)
 (Address, zip code and telephone number of principal executive offices)

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

Securities registered pursuant to Section 12(g) of the Act: 
Common Stock - $1.00 Par Value

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, 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 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 ]

At October 1, 1996, non-affiliates held 3,067,297 shares of the Registrant's
$1 par value common stock. On December 2, 1996, the aggregate market value of 
those shares was $62,112,764.

At the close of business on December 20, 1996, the registrant had 3,243,543 
outstanding shares of its $1.00 par value common stock.

               DOCUMENTS INCORPORATED BY REFERENCE

Incorporated  Document                         Location in Form 10-K

Portions of the Proxy Statement furnished to Shareholders Part III
in connection with Annual Meeting to be held February 5, 1997.




                       Page 1 of 46 pages
          Exhibit Index appears on Pages 43 through 45.
<PAGE> 2
                        TABLE OF CONTENTS

Part I                                                   Page No(s).
                                                          ---------

  Item 1                                                  Business
     General                                                 4-5
     The Utility Gas Distribution Business                   5-6
     The Retail Propane Business                              6
     Summary of Revenues                                      6
     Deregulation                                            6-7
     Competition                                              7
     Gas Supply
        General                                               7
        Supply Contracts and Storage                         7-8
        Controlled Attachment Policy                          8
        Cost of Purchased and Produced Gas                   8-9
     Supervision and Regulation                               9
     Employees                                                9
     Executive Officers of the Registrant                    10
  Item 2.Properties                                         10-11
  Item 3.Legal Proceedings                                  11-12
  Item 4.Submission of Matters to a Vote of Security
         Holders                                             12

Part II

  Item 5.  Market for Registrant's Common Equity and
           Related Stockholder Matters                       13
  Item 6.  Selected Financial Data                           14
  Item 7.  Management's Discussion and Analysis of
           Financial Condition and Results of Operations    15-20
  Item 8.  Financial Statements and Supplementary Data      21-38
  Item 9.  Changes in and Disagreements with Accountants
           on Accounting and Financial Disclosure            38

Part III

  Item 10. Directors and Executive Officers of the
           Registrant                                        38
  Item 11. Executive Compensation                            38
  Item 12. Security Ownership of Certain Beneficial
           Owners and Management                             39
  Item 13. Certain Relationships and Related Transactions    39
<PAGE> 3
                  TABLE OF CONTENTS (continued)
                                
Part IV                                                  Page No(s).
                                                           --------

  Item 14. Exhibits, Financial Statement Schedules,
           and Reports on Form 8-K                          39-41
  Signatures                                                  42
  Exhibit Index                                             43-45

<PAGE> 4
                        ENERGYNORTH, INC.
                            FORM 10-K
                                
                             PART I

ITEM 1.  BUSINESS

General

The business of EnergyNorth, Inc., incorporated in the State of 
New Hampshire in 1982, is the ownership of 100% of the 
outstanding common stock of EnergyNorth Natural Gas, Inc.
("ENGI"), EnergyNorth Propane, Inc. ("ENPI"), and EnergyNorth
Realty, Inc. EnergyNorth, Inc. ("ENI" or the "Registrant"), and its 
subsidiaries, collectively referred to as the "Company", are
headquartered at 1260 Elm Street, Manchester, New Hampshire,
except for ENPI, which is headquartered at 75 Regional Drive,
Concord, New Hampshire.  All subsidiaries are incorporated in the
State of New Hampshire.

The business of ENGI, the Registrant's principal subsidiary, is
the purchase, transportation and sale of natural gas for
residential, commercial and industrial use in New Hampshire.
ENPI is a retailer of liquefied petroleum gas ("propane" or "LP")
and serves customers in central and southern New Hampshire.
During 1996, ENPI entered into a joint venture with Northern New
England Gas Corporation, creating a limited liability company to
provide LP gas sales and service in the State of Vermont.

In general, the senior management of ENI serves as the senior
management of all subsidiaries.  The Company provides for the
subsidiaries' administrative support and services and establishes
policies, plans and goals.

The service territory of ENGI has a population of approximately
463,000 in 27 communities situated in southern and central New
Hampshire, which includes the communities of Nashua, Manchester,
Concord and Laconia.  The service area encompasses approximately
911 square miles.  Located within 30 to 85 miles of Greater
Boston, ENGI's service territory offers a favorable business
climate with no general sales or personal income taxes, a productive 
labor force and a comfortable, safe and clean environment
for residents and tourists.

The State of New Hampshire's job growth continues to be robust,
ranking first among New England states with a 1.9% growth rate.
This compares to a 1.9% average growth rate nationally and a 1.4%
average rate for New England.  According to The New England
Economic Project's October 1996 Economic Outlook for New
Hampshire, new housing permits are expected to increase 3.2% in
1997 over 1996. While the New Hampshire unemployment rate for
1997 is forecasted at 4% compared to 3.8% in 1996, the labor
force is forecasted to increase by 1.2% in 1997.  In fiscal 1996,
the Company experienced net growth of over 2.4% in natural gas
customers and almost 9.4% in propane customers over 1995.
<PAGE> 5
ENGI's marketing focus continues to stress low cost growth by
concentrating on adding new customers along the Company's more
than 1,000 miles of gas mains and adding load from the existing
customer base.  ENGI has a 30% - 35% share of the home heating
market within its service territory, creating a potential for
increased sales where the natural gas pipeline is located and
alternative fuels are used.  In New Hampshire, fuel oil has a
penetration of over 57% of the home heating market. Currently,
the comparative full service price of natural gas for heating is
less than fuel oil.  From a total energy perspective, natural gas
is a strong competitor with a complete range of gas appliances
and uses, including ranges, water heaters, clothes dryers,
fireplaces and gas logs, outdoor lights and natural gas heat
pumps for heating and cooling.  While these multiple uses provide
opportunities to be the total energy provider to new customers,
it also provides opportunities for expansion within the existing
customer base.  Due to continued customer conversions from other
energy sources and expansion of its service territory, ENI has an
opportunity for growth in the retail sales market.  During the
past five years, ENGI has experienced an annual average customer
growth rate of about 2.0% compared to the 1.5% national average
for local distribution companies. Additional growth in
distribution operations may also occur as industrial and
commercial customers turn to natural gas for electric generation
because of a price advantage and as a means to ensure compliance
with the provisions of the Clean Air Act.  As the electric
industry continues to move toward deregulation, this option
becomes more attractive.  The development of new gas-burning
technologies for industry and the wider acceptance of natural gas
as a fuel for motor vehicles have provided opportunities for
increased gas usage in market sectors that are not sensitive to
the weather.

The Utility Gas Distribution Business

ENGI distributes natural gas as a regulated utility pursuant to
franchise authority granted by the New Hampshire Public Utilities
Commission (the "Commission").  No operations are outside New
Hampshire.  While the franchise area of ENGI is primarily
residential in character, sales volumes are almost evenly split
between residential and commercial/industrial customers.  As of
September 30, 1996, the Company's utility business served over
66,000 customers, of which approximately 88% were residential and
12% were commercial and industrial.  During fiscal 1996, no ENGI
customer purchased more than 4% of the total ENGI annual sales
volume.

In fiscal 1994, ENGI unbundled its services by providing a new
transportation-only service for both firm and interruptible,
large commercial and industrial customers. Transportation service
allows customers to purchase a natural gas supply directly from
gas marketers who deliver that gas supply to an ENGI gate station
and contract with ENGI for local transportation to their
facilities.  To ensure a continual, uninterrupted supply, ENGI
also provides an optional, separate standby service as a backup
to the gas supplies of transportation customers.  During 1996,
ENGI provided transportation service to 29 customers.  Under the
present regulatory environment, a switch to transportation
service will reduce sales volumes and resulting utility gross
revenues, but will not have an impact on gross margin. Current
rates established for firm transportation by the Commission
provide the same margin as firm sales service.  ENGI is currently
involved in a proceeding at the Commission to determine the costs
of providing transportation service.  A decision in this
proceeding may result in a reduction in current transportation
rates and a corresponding decrease in transportation margin.
ENGI cannot predict the impact, if any, that the results of this
proceeding may have on future operations.
<PAGE> 6
ENGI distributes gas to substantially all of its utility
customers through a system of underground pipelines connected
with its three operations centers in Manchester, Nashua and
Tilton, six take stations located in Manchester, Londonderry,
Windham, Concord, Hooksett and Suncook and four production plant
facilities in Manchester, Nashua, Concord and Tilton.  The
pipelines are generally located in public ways and are subject to
licenses granted by municipalities.  ENGI serves over 75% of New
Hampshire's natural gas customers.

The Retail Propane Business

ENPI sells propane to residential, commercial and industrial
customers in more than 100 communities primarily located within a
50-mile radius of Concord.  Propane distribution does not require
a regulatory franchise.  Propane is delivered to customers by
trucks from ENPI's liquid propane storage facilities located in
communities within ENPI's service territory.  ENPI purchases the
majority of its liquid propane requirements on a firm contractual
basis. The remaining liquid propane requirement is purchased in
the spot market.  During 1996, ENPI entered into a joint venture
with Northern New England Gas Corporation to provide LP gas sales
and service in Vermont.  ENPI holds a 49% interest and will
provide planning and management expertise to the joint venture.

Summary of Revenues
<TABLE>
Revenues, in thousands of dollars, attributable to various
categories of gas distribution and related operations during the
last three fiscal years are as follows:
<CAPTION>
                                              September 30,
                                        ---------------------------
                                           1996      1995      1994
                                        -------   -------   -------
<S>                                     <C>       <C>       <C>
Utility (natural gas) sales service     $76,007   $69,067   $88,150
Utility transportation service            1,503       749         -
Propane gas sales                        11,444     8,990     8,900
Service and appliance sales               1,917     1,794     1,718
Rentals                                     987       964       917
                                        -------   -------   -------
                                        $91,858   $81,564   $99,685
                                        =======   =======   =======
</TABLE>
During the winter period, November 1 through March 31, the
Company's gas revenues are substantially higher than during the
summer months.  The increase in gas revenues during the winter,
and the concomitant increase in gas supply requirements, occurs
because approximately 89% of ENGI's customers use natural gas for
heating.

Deregulation

The implementation of Federal Energy Regulatory Commission
("FERC") Order 636 provided for the unbundling and deregulation
of the interstate pipeline system and led to the beginning of
unbundling of the intrastate pipeline system in New Hampshire.
In late 1993, the Commission approved gas transportation rates
and separate standby and balancing services for commercial and
industrial customers.
<PAGE> 7
Gas transportation services have allowed customers to utilize
ENGI's distribution system for the transportation of gas
purchased from third-party gas marketers, creating competition
from gas marketers for the sale of gas to end users.  At
September 30, 1996, 29 customers had entered into transportation
agreements with ENGI. These customers are, for the most part,
large commercial and industrial customers.  The volume
transported for transportation customers in fiscal 1996 was
514,000 Mcf, approximately 4% of ENGI's total gas sales.

ENGI is the sole distributor and transporter of natural gas in
its franchise area.  The Tennessee Gas Pipeline Company
("Tennessee") is the only interstate pipeline to serve ENGI's
franchise area.  For that reason, and because installation of
private transmission mains would typically be impractical,
customers have not attempted to bypass ENGI's distribution
system.

Competition

Natural gas competes mainly with electricity and fuel oil.  The
principal competitive factors between natural gas and alternative
fuels are the price of the fuel and the conversion costs from one
fuel to another.  Competition is greatest among ENGI's commercial
and industrial customers who have the capability to use
alternative fuels.  ENGI provides flexible rates for users with
dual-fuel capabilities in order to better compete with the
alternative fuels.

Natural gas has a significant price advantage over electricity.
Natural gas heating costs are typically less than one-half of
electric heating costs.  At the present time, the price of
natural gas is less than the price of oil for heating.  ENGI
continues to add customers because energy decisions are also
based on factors other than cost. Demand is expected to continue
to increase as national attention remains focused on natural gas
because of its environmental advantages, efficiency and security
of supply. Additionally, commercial and industrial customers
continue to find gas technologies and equipment attractive as
they deal with the requirements of the Clean Air Act Amendments
of 1990 and other Federal environmental legislation.

The retail propane market is very competitive, and several other
retail propane operations exist within the communities served by
ENPI.  The principal competitive factors in the industry are
price, dependability of delivery and service.

Gas Supply

General.  The Company's gas supply goal is to maintain a balanced
portfolio of supply that will continue to minimize the overall
cost of gas while providing the necessary security to meet demand
requirements.

Supply Contracts and Storage.  ENGI's gas supply is principally
natural gas transported by the interstate pipeline system.  ENGI
has contracted with Tennessee to deliver 56,833 Dths per day on a
<PAGE> 8
firm transportation basis and up to 8,000  Dths per day on an
interruptible basis. Natural gas supplies are purchased both on a
long-term contract and short-term spot market basis.  During
1996, ENGI purchased approximately 6.2% of its annual natural gas
requirements in the spot market.  At times during the year,
typically during the summer, ENGI will purchase lower cost spot
market natural gas supply.  ENGI's long-term contracts, under
which it has firm supply for approximately 32,529 Dths per day,
have remaining terms of three to ten years.

In fiscal 1996, approximately 68% of ENGI's gas requirements came
from domestic pipeline sources, 21% from Canadian pipeline
supplies and approximately 10% from supplemental pipeline
supplies.  LP and liquefied natural gas ("LNG") purchases from
both domestic and foreign sources made up approximately 1% of
ENGI's total supply requirements.  Supplemental supplies of gas
are produced from plants owned and operated by ENGI.

All pipeline volumes are transported by Tennessee under FERC
tariffed rate schedules.  The supply from Canada is transported
to Tennessee's system using the TransCanada and the Iroquois Gas
transmission systems.

In addition to long-term supply sources, ENGI stores gas during
the summer months under long-term contracts with the owners of
storage facilities located in Pennsylvania and New York.  Gas
from these storage facilities, up to 24,304 Dths per day on a
firm basis, is delivered to ENGI during the winter months through
the Tennessee system.  ENGI owns other on-site storage facilities
capable of holding 125,438 Dths of LP and 13,057 Dths of LNG.

ENGI has contracted for 1,760,000 Dths of supplemental gas vapor,
75,000 Dths of LNG and an additional 1,000,000 gallons of LP for
the winter of 1996-1997.

The Company expects to be able to secure the gas supply required
to meet new customer demands through long-term commitments and
purchases in the spot market.

Controlled Attachment Policy. The controlled attachment policy is
a tariff provision that restricts sales to large commercial and
industrial firm customers. The controlled attachment policy for
year-round natural gas customers provides for a reasonable
balance between gas supply and the requirements of current and
future customers in the ENGI franchise area. Sales to new
customers and additional sales to existing customers are limited
to 250 Mcf per day per customer.  The daily Mcf limits do not
apply for interruptible and 280-day customers who have available
standby fuel and equipment and who agree to limit their
consumption if requested by ENGI.

Cost of Purchased and Produced Gas.  The average unit cost of gas
purchased and produced during the twelve months ended September
30, 1996 was approximately $3.96 per Mcf compared to $3.44 per
Mcf for the same period last year.  The 1996 average unit cost
reflects higher pipeline costs due to supplier rate case
settlements and higher cost of  gas supply in the marketplace.
The Cost of Gas Adjustment ("CGA") clause authorized by the
Commission permits recovery by ENGI, from its customers, of gas
costs (including pipeline, LP, LNG and storage) that are higher
or lower than the
<PAGE> 9
cost of gas included in base rates. The CGA is determined twice
annually, for summer and winter periods.

Margins earned on interruptible, 280-day sales and capacity
release are passed on to firm customers through the CGA. In
addition, costs associated with a gas inventory trust, including
administration fees and carrying costs, are recovered through the
CGA.

ENGI is subject to payment of transition costs associated with
FERC Order 636 restructuring. Tennessee began billing these costs
late in fiscal 1993 and ENGI has incurred $5.9 million in
transition costs through September 30, 1996 and is recovering
these costs through the CGA.  Based on current information,
additional transition costs are expected to range from $1.7
million to $5.1 million. Meanwhile, ENGI customers are benefiting
from the restructuring, realizing long-term savings in gas costs.

Supervision and Regulation

ENI is generally exempt from regulation under the Public Utility
Holding Company Act of 1935, because its utility operations are
predominantly intrastate in character.

ENGI is subject to regulation by the Commission, which has
authority over accounting, rates and charges, the issuance of
securities and certain operating matters. Changes in utility
rates and charges cannot be made without 30 days notice to the
Commission, which has the power to suspend, investigate and
change any proposed increase in rates and charges. Neither New
Hampshire statutes nor regulations of the Commission, by their
terms, subject ENGI to direct supervision or regulation by the
Commission except with respect to the acquisition of other New
Hampshire public utility holding companies or public utilities.

The gas distribution businesses of ENGI and ENPI are subject to
extensive safety regulations and reporting requirements
promulgated by the United States Department of Transportation,
but are not otherwise subject to direct regulation by Federal
agencies except as to environmental matters.  These subsidiaries
are also subject to zoning and other regulations by local
authorities, and their capital expenditures, earnings and
operations have not been materially affected by environmental and
local regulation.

Employees

At September 30, 1996, the Company had 250 full-time employees of
whom 136 were represented by four contracts with Local 12012 of
the United Steelworkers of America.  Two union contracts covering
27 employees expire in 1997 and two covering 109 employees expire
in 2001.
<PAGE> 10
Executive Officers of the Registrant
<TABLE>
The executive officers of the Registrant are listed below,
together with age at December 20, 1996, position and other
information as to each.  The term of office of each executive
officer terminates when his successor shall have been duly
elected and qualified.
<CAPTION>
                             Served  Principal Occupations and
                             as      Employement During Last Five
Name and Position            Officer Years Other Than with
with the Registrant     Age  Since   the Registrant
--------------------    ---  ------- ----------------------------

<S>                     <C>  <C>     <C>
Robert R. Giordano      58   1982    Chief Executive Officer and
  President and Chief                President of ENGI; Chairman
  Executive Officer                  and Chief Executive Officer
                                     of ENPI

Albert J. Hanlon        55   1988    Senior Vice President of ENGI
  Senior Vice President

Michelle L. Chicoine    40   1990    Vice President (since 1993),
  Vice President,                    Treasurer (since 1990) and
  Treasurer and Chief                Chief Financial Officer (since   
  Financial Officer                  1996) of ENGI

Frank L. Childs         52   1995    Vice President of ENGI (since
  Vice President                     1995); formerly (1992-1994) 
                                     Executive Vice President and
                                     Chief Administrative Officer
                                     of UNITIL Corporation;
                                     formerly President (until
                                     1994) and Chief Operating
                                     Officer (until 1992) of
                                     Fitchburg Gas and Electric
                                     Light Company

Richard P. Demers       60   1988    President of ENPI and Vice
  Vice President                     President of ENGI

David A. Skrzysowski    50   1983    Vice President and Controller
  Vice President and                 of ENGI
  Controller
</TABLE>

ITEM 2.  PROPERTIES

The Company's utility gas distribution facilities constitute the
majority of its physical assets.  As of September 30, 1996, ENGI
had approximately 1,020 miles of mains and 640 miles of service
connections.  The utility's mains and service connections are
adequate to meet service requirements and are maintained through
a regular program of inspection and repair.  Offices and
operations centers located in Nashua, Manchester, Concord and
Tilton are adequate for the needs of the Company and are
regularly maintained and in good condition.  Substantially all of
the Company's properties are fully utilized.
<PAGE> 11
Substantially all of the Company's utility properties are subject
to the liens of the indentures securing the ENGI General and
Refunding Bonds.  In some cases, motor vehicles and nonutility
assets are subject to purchase money security interests held by
banks.  The Manchester office building and substantially all of
ENPI's assets are subject to first mortgages. The Company also
has long-term leases for motor vehicles, office equipment and
computer equipment.

ITEM 3.  LEGAL PROCEEDINGS

The Company is a party in several routine proceedings.  Such
actions, for the most part, are covered by insurance and, to the
extent that they are not fully covered, the damages sought are
not material in amount.  ENGI is currently participating in a
proceeding at the Commission to determine the costs of providing
transportation service.  ENGI cannot predict the impact, if any,
a decision in this proceeding may have on future operations.
ENGI is a party to various other Commission proceedings relating
to operations, none of which is expected to have a material
impact on the Company's earnings or assets.

In 1995, ENGI completed the disposal of the contents of the
gasholder situated on a former gas manufacturing site in Concord,
New Hampshire.  Total remediation costs amounted to approximately
$3.5 million. Recovery of these costs from customers began on
July 1, 1995 and will extend over a seven-year period. The
unamortized balance of $3.0 million at September 30, 1996 is
excluded from rate base.

The New Hampshire Department of Environmental Services ("NHDES")
has selected a remedial action for a portion of the Concord site
at which wastes were disposed of between the late 1800's and the
mid-1900's.  The estimated cost of the remedial action ranges
from $2.9 million to $4.8 million, and the Company has recorded
$2.9 million at September 30, 1996 in deferred charges.

The Company and another utility company have been directed by the
NHDES to conduct an environmental site characterization of a
former manufactured gas plant in Laconia, New Hampshire. The
Laconia manufactured gas plant operated between approximately
1887 and 1952, and the Company owned and operated the facility
for approximately the last seven years of its active life.
Without admitting liability, the Company and the other utility
have entered into an agreement under which the costs of the site
characterization are shared.  The Company's share of the costs of
the site characterization and a report to the NHDES, which is
underway, is expected to total $88,000 and has been recorded in
deferred charges as of September 30, 1996.  The Company is
currently unable to predict the magnitude of any liability that
may be imposed on it for the cost of additional studies or the
performance of a remedial action in connection with the Laconia
site.

The Company will pursue recovery from insurance carriers and
claims against any other responsible parties seeking to ensure
that they contribute appropriately to reimburse the Company for
any costs incurred with respect to environmental matters.  The
Company intends to seek and expects to receive approval of rate
recovery methods with respect to environmental matters after it
has determined the extent of contamination, received
recommendations with regard to remediation and commenced
remediation efforts.
<PAGE> 12
On September 12, 1995 the Company filed a Complaint in the United
States District Court for the District of New Hampshire against
UGI Utilities, Inc., as the successor to United Gas Improvement
Company.  The Company seeks contribution for expenses incurred at
the Concord site based upon the operation of the manufactured gas
plant by the United Gas Improvement Company, a predecessor of UGI
Utilities, Inc., during a period of time the manufactured gas
plant was in operation.

On December 8, 1995 ENGI filed suit in the United States District
Court for the District of New Hampshire against Associated
Electric and Gas Insurance Services, Ltd., American Home
Assurance Company, CIGNA Specialty Insurance Company,
International Insurance Company, Lloyd's, Underwriters at London,
Lexington Insurance Company, National Union Fire Insurance
Company, later adding Columbia Casualty Company as a defendant,
seeking a declaratory judgment that they owe ENGI a defense
and/or indemnification for environmental claims associated  with
the Concord facility.  ENGI filed suit in the New Hampshire
(Hillsborough County) Superior Court on December 8, 1995 against
the Continental Insurance Company and Netherlands Insurance
Company seeking a declaratory judgment that they owe ENGI a
defense and/or indemnification for environmental claims
associated with the Concord facility.


ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matter was submitted to a vote of security holders in the
fourth quarter of fiscal 1996.

<PAGE> 13
                                                          PART II
ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
         STOCKHOLDER MATTERS
<TABLE>
Outstanding shares of the Company's common stock are listed and
traded on the New York Stock Exchange with the symbol "EI."  High
and low sales prices during 1996 and 1995 were as follows:
<CAPTION>
                                 Fiscal 1996         Fiscal 1995
                               High      Low       High      Low
   -------------------------------------------------------------
   <S>                      <C>      <C>            <C>  <C>
   First Quarter            $18 3/8  $16 5/8        $18  $15 1/4
   Second Quarter            20       17             18   15 1/2
   Third Quarter             19 7/8   18 1/4         18   15 3/4
   Fourth Quarter            19 3/4   18 1/8         18   16 3/8


<CAPTION>
As of December 2, 1996, there were approximately 2,300 holders of
record of common stock.

Quarterly cash dividends paid were as follows:
                         Fiscal 1996      Fiscal 1995
                         -----------      -----------
   <S>                         <C>              <C>
   First Quarter               $.29             $.28
   Second Quarter               .29              .28
   Third Quarter                .305             .28
   Fourth Quarter               .305             .28
</TABLE>

<PAGE> 14
<TABLE>
ITEM 6.  SELECTED FINANCIAL DATA

(In thousands, except per share amounts)
<CAPTION>
                                     1996       1995       1994      1993*       1992
                                 --------   --------   --------   --------   --------
<S>                              <C>        <C>        <C>        <C>        <C>
Total operating revenues         $ 88,954   $ 78,806   $ 97,050   $ 86,197   $ 80,007    
                                                                   
Earnings applicable to
common stock                        6,078      4,104      5,422      5,368      3,673
                                                                   
Earnings per share                   1.89       1.30       1.74       1.74       1.22

Cash dividends per share             1.19       1.12       1.08       1.06       1.04

Total assets                      132,003    121,337    121,019    113,569    106,710

Capitalization:
  Common stockholders' equity      45,167     42,114     40,778     38,054     35,204
  Long-term debt (including
  capital lease obligations)       29,571     30,103     33,501     35,588     35,687
                                 --------   --------   --------   --------   --------
    Total capitalization         $ 74,738   $ 72,217   $ 74,279   $ 73,642   $ 70,891
                                 ========   ========   ========   ========   ========
Short-term debt(including
current portion of
long-term debt)                  $ 11,854   $  5,501   $  2,308   $  4,998   $  5,270
</TABLE>

________________________
See notes 8 and 9 to the consolidated financial statements for
information related to accounting changes.

Reclassifications are made periodically to previously issued
financial data to conform to the current presentation.

*  Results include a credit to earnings for previously disallowed
gas costs, net of tax, of $959.
<PAGE> 15
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
         CONDITION AND RESULTS OF OPERATIONS

Earnings and Dividends

Earnings per share for 1996 were $1.89 on record net income of
$6.1 million, which represents a 45% increase from the $1.30 per
share earned in 1995.  Return on average common equity for 1996
was 13.9%, bettering the previous year's 9.9% return.  The 1996
increase in earnings was primarily due to greater margins
resulting mostly from growth in volumes delivered. Volumes of
firm gas delivered to utility customers increased 13.1% to 11.4
million Mcf, and propane gallons sold increased almost 21% in
1996.  Weather in the Company's service area was near normal in
1996 but 9.5% colder than the prior year.  In 1995, earnings were
reduced by approximately $.50 per share, after taxes, as a result
of warmer temperatures.  In addition, 1995 earnings included a
$215,000 after-tax gain ($.07 per share) on the sale of railcars.

The Company's Board of Directors increased the quarterly dividend
8.9% during the fiscal year.  The current quarterly dividend of
30.5 cents per share is equal to an annual dividend of $1.22 per
share.  Cash dividends paid to common shareholders in 1996 were
$3,826,000, representing a payout ratio of 63% of 1996 earnings.

Utility Sales and Revenues

Utility gas service operating revenues were $77.5 million in
1996, compared to $69.8 million in 1995.  The increase resulted
primarily from increased volumes delivered to firm residential
and commercial heating customers.  The weather in 1996 was 9.5%
colder than in 1995.  In addition, customer growth in 1996 was
approximately 1.7%. Revenues from gas transported for customers
under firm transportation service rates increased more than 40%
to $979,000, due to a 45% increase in volumes transported. This
increase included a shift of 162,000 Mcf from firm commercial and
industrial sales customers, representing a decrease of $516,000
in operating revenue attributable to the commodity cost of gas.
The Company generates revenues through the sale and
transportation of natural gas.  Shifts between transportation and
sales gas will cause variations in natural gas revenues since the
transportation rate does not include the commodity cost of gas,
which is billed directly to the customer by its marketer.  The
Company's rate structure allows for similar margins on
transported and sales gas.  The Company is currently involved in
a proceeding at the New Hampshire Public Utilities Commission
(the "Commission") to determine the costs of providing
transportation service.  A decision in this proceeding may result
in a reduction in current transportation rates and a
corresponding decrease in transportation margin.  The Company
cannot predict the impact, if any, that the results of the
proceeding may have on future operations.  At September 30, 1996,
the Company had 29 transportation customers compared to 21
customers the previous year. Interruptible revenue and
interruptible transportation revenue increased $895,000 in 1996
to $4.6 million.  Interruptible margins are used to lower charges
to firm customers through the cost of gas adjustment ("CGA") and
do not impact the Company's profitability.
<PAGE> 16
The Company's tariff includes CGA rates which provide for
increases and decreases in the rates charged for gas to reflect
estimated changes in the cost of gas.  Although changes in CGA
rates affect revenues, they do not affect total margin because
the CGA is a tariff mechanism designed to provide dollar-for-dollar
recovery of gas costs.  Amounts recovered under CGA rates
are reconciled biannually against actual costs, and future CGA
rates are adjusted accordingly.

Utility Cost of Gas Sold

Cost of gas was $39.5 million in 1996 and $36.1 million in 1995.
The increase was primarily due to higher prices from suppliers
($5.9 million) and the increase in delivered volumes ($4.7
million), partially offset by timing differences related to the
recovery of gas costs through the CGA ($7.2 million).  The
average unit cost of gas sold in 1996 was $3.96 per Mcf, compared
to $3.44 per Mcf in 1995.  Increases or decreases in purchased
gas costs from suppliers have no significant impact on margin, as
they are passed on to customers through the CGA.

Retail Propane Operations

Retail propane operations contributed $646,000 to net earnings of
the Company, an increase of $276,000 over 1995 results.  1996
operating revenues increased $2.4 million to $11.4 million, as
propane gallons sold increased almost 21%.  Substantial customer
growth and the colder weather accounted for the increase in
gallons sold.  The average number of propane customers increased
more than 10% in 1996.  Despite an increase in the unit cost of
gas of 10.5% and competitive pressure to maintain price, gross
margin increased $982,000 or 21%.  Operations and maintenance
expense increased more than $425,000, primarily as a result of
increases in labor, transportation and other delivery related
expenses necessary to support an expanding customer base.

Operating Expenses

Operations and maintenance expense increased $614,000, or less
than 3%, to $21.7 million in 1996.  Reductions in the work force,
other cost saving initiatives and workers' compensation and
health insurance refunds helped offset most of the increases from
liability insurance, uncollectible accounts and other
administrative expenses.

Depreciation and amortization expense increased from $5.1 million
to $5.8 million in 1996, consistent with the Company's continued
investment in the expansion and upgrading of its distribution
system and facilities.  Net additions to property, plant and
equipment were $8.8 million and $7.9 million in 1996 and 1995,
respectively.

Taxes other than income taxes increased $193,000 to $3.9 million
primarily due to increases in property taxes, resulting from
property tax rate increases and additions to taxable property.
<PAGE> 17
A higher level of pretax income was the main reason for the $1.7
million increase in total Federal and state income taxes in 1996.
In addition, as a result of the resolution of certain tax issues,
the Company reduced Federal income taxes by $200,000 in 1995.

Total other income for 1995 includes a gain of $350,000 from the
sale of railcars formerly used to transport liquid propane.

Fiscal 1996 interest expense decreased 12.9% from 1995 due mainly
to the repayment of $3.8 million of long-term debt and a decrease
in average short-term borrowings and average short-term interest
rates.

Capital Resources and Liquidity

Because of the seasonal nature of the Company's operations, a
substantial portion of cash receipts are generated during the
November-March heating season, which results in the highest cash
inflow during late winter and early spring.  However, cash
requirements for capital expenditures, dividends, long-term debt
retirement and working capital do not track this pattern of cash
receipts.  The greatest demand for cash is in the fall and early
winter to support the completion of the annual construction
program, and to fund gas inventories and other working capital
requirements.

Cash provided by operations and financing activities was
sufficient to fund investing activities in 1996.  Higher earnings
due to increased margins from greater sales volumes had a
favorable impact on funds provided by operating activities.
Additionally, during 1996, the Company raised almost $802,000 of
common equity through the Dividend Reinvestment and Stock
Purchase Plan.  Borrowings against lines of credit during 1996
ranged from zero to a high of $9.5 million. In addition, the
Company refinanced a $1.5 million mortgage note.  The Company's
major uses of cash were capital expenditures of $8.8 million,
environmental remediation of $672,000 and retirement of $3.8
million of long-term debt.  Deferred gas costs increased $9.4
million, due to the timing of the recovery of increased gas costs
through the CGA.  In addition, dividend payments to shareholders
totaled $3.8 million in 1996.

Capital expenditures for 1997 are currently projected at
approximately $10.3 million, and annual sinking fund requirements
and maturities of long-term debt are scheduled to be $2.3 million
in 1997.  Additional cash requirements will be necessary for the
payment of dividends, environmental remediation and working
capital.  Cash to fund these requirements is expected to be
provided principally by internally generated funds and short-term
bank borrowings under the Company's lines of credit.  At
September 30, 1996, the Company had available lines of credit
aggregating $13.0 million with $9.5 million outstanding.  In
addition, a credit line of $9.5 million was available at
September 30, 1996 under the Company's inventory trust financing
plan.  At September 30, 1996, the Company's inventory in trust on
the consolidated balance sheet was $7.8 million with an
outstanding purchase obligation of $7.9 million.
<PAGE> 18
On September 30, 1996, the Company's capitalization ratio
consisted of 52% common equity and 48% debt, including short-term
debt.  Return on average common equity was 13.9%. In order to
contribute to both stability and the ability to market new
securities when appropriate, the Company attempts to maintain a
balanced capital structure.  The Company will seek future debt
and equity financing based upon the amount and timing of
internally generated funds, rate relief, regulatory actions and
market conditions.

Environmental Matters

The Company and certain of its predecessors owned or operated
facilities for the manufacture of gas from coal, a process used
through the mid-1900's that produced by-products that may be
considered contaminated or hazardous under current law, and some
of which may still be present at such facilities.  The Company
accrues environmental investigation and clean-up costs with
respect to former manufacturing sites and other environmental
matters when it is probable that a liability exists and the
amount or range of amounts is reasonably certain.

A former manufactured gas facility in Concord, New Hampshire has
been investigated and partially remediated.  Disposal of the
contents of the gasholder situated at this former gas
manufacturing facility has been completed.  Total remediation
costs amounted to approximately $3.5 million and were recorded in
deferred charges.  Recovery of costs from customers began on July
1, 1995 and will extend over a seven-year period.  The
unamortized balance of $3.0 million at September 30, 1996 is
excluded from rate base.

The New Hampshire Department of Environmental Services ("NHDES")
has selected a remedial action for a portion of the Concord site
at which wastes were disposed of between the late 1800's and 
mid-1900's.  The estimated cost of the remedial action ranges from
$2.9 million to $4.8 million, and the Company has recorded $2.9
million at September 30, 1996 in deferred charges.

The Company is pursuing recovery from its insurance carriers as
well as from insurance carriers of its predecessors with respect
to the Concord site.  In addition, the Company is pursuing
recovery against an entity that the Company alleges owned or
operated the manufactured gas plant during the late 1800's and
early 1900's.

The Company and another utility company have been directed by the
NHDES to conduct an environmental site characterization of a
former manufactured gas plant in Laconia, New Hampshire. The
Laconia manufactured gas plant operated between approximately
1887 and 1952, and the Company owned and operated the facility
for approximately the last seven years of its active life.
Without admitting liability, the Company and the other utility
have entered into an agreement under which costs of the site
characterization are shared.  The Company's share of the costs of
the site characterization and a report to the NHDES, which is
underway, is expected to total $88,000 and has been recorded in
deferred charges as of September 30, 1996.  The Company is
currently unable to predict the magnitude of any liability that
may be imposed on it for the cost of additional studies or the
performance of a remedial action in connection with the Laconia
site.
<PAGE> 19
The Company will pursue recovery from insurance carriers and
claims against any other responsible parties seeking to ensure
that they contribute appropriately to reimburse the Company for
any costs incurred with respect to environmental matters.  The
Company intends to seek and expects to receive approval of rate
recovery methods with respect to environmental matters after it
has determined the extent of contamination, received
recommendations with regard to remediation and commenced
remediation efforts.

Results of Operations 1995 Compared to 1994

Net income declined to $4.1 million in 1995 from record 1994 net
income of $5.4 million.  Earnings per share in 1995 were $1.30
compared to $1.74 in 1994.  A key reason for the decrease in net
income was the impact on operations of significantly warmer
weather during the 1995 heating season.  The effect of weather,
when compared to normal, reduced 1995 net income by approximately
$.50 per share, after taxes.  In 1994, net income increased $.30
per share, after taxes, as a result of the record colder than
normal temperatures.

Operating revenues were approximately $78.8 million in 1995, a
decrease of 18.8% from 1994.  The total volume of gas sendout
declined 7.5% as temperatures in 1995 were 13.3% warmer than in
1994 and 9.2% warmer than normal.  The average number of utility
customers increased 2.1% to more than 65,000 in 1995.  Utility
gas service revenues, which represented 88.6% of total operating
revenues, decreased by $18.4 million or 20.9%.

Propane operations recorded $9.0 million in total operating
revenues in 1995, a slight increase over 1994.  The increase was
primarily due to a 12% increase in the average number of propane
customers to 10,800 in 1995.  Propane gallons sold decreased
almost 2% in 1995 due to the effect of warmer weather.

The average unit cost of gas purchased and produced decreased to
$3.44 per Mcf in 1995 from $4.03 per Mcf in 1994.

Operations and maintenance expense decreased 3.5% in 1995,
primarily because of reductions in the work force combined with
reductions in workers' compensation insurance and bad debt
expense.

Capital expenditures for the Company's continuing expansion and
system improvement programs were the reason for the 4.5% increase
in depreciation and amortization in 1995.

A gain of $350,000 from the sale of railcars formerly used to
transport liquid propane is included in total other income for
1995.

Total interest expense was $4.3 million in 1995, or 9.3% greater
than 1994.  The Company's total average short-term borrowings and
the weighted average short-term interest rate were greater than
in 1994.
<PAGE> 20
Total Federal and state income taxes decreased $644,000 in 1995.
The lower level of pretax income and the resolution of certain
tax issues are the principal reasons for the decrease.  Partially
offsetting the decrease was the impact of the repeal of the
franchise tax.  The Company's gas distribution subsidiary
recorded state income taxes of $359,000 in 1995.  No state income
taxes were recorded in 1994 for this subsidiary.

Factors That May Affect Future Results

The Private Securities Litigation Reform Act of 1995 encourages
the use of cautionary statements accompanying forward-looking
statements.  The preceding Management's Discussion and Analysis
of Financial Condition and Results of Operations includes forward-
looking statements concerning the impact of transportation
customers on the Company's profitability; the impact of changes
in the cost of gas and of the CGA mechanism on total margin;
projected capital expenditures and sources of cash to fund
expenditures; and estimated costs of environmental remediation
and anticipated regulatory approval of recovery mechanisms.  The
Company's future results, generally and with respect to such
forward-looking statements, may be affected by many factors,
among which are uncertainty as to the precise rates for
transportation of gas that will be allowed by the regulators and
as to the number and size of sales gas customers who become
transportation-only customers; uncertainty as to the regulatory
allowance of recovery of changes in the cost of gas; uncertain
demands for capital expenditures and the availability of cash
from various sources; and uncertainty as to the regulatory
approval of the full recovery of environmental costs, transition
costs, and other regulatory assets.
<PAGE> 21
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

      (a)  Financial Statements required by Regulation S-X
<TABLE>
Consolidated Statements of Income                  EnergyNorth, Inc.
<CAPTION>
(In thousands, except per share amounts)
For the years ended September 30,          1996      1995      1994
-------------------------------------------------------------------
<S>                                     <C>       <C>       <C>
Operating revenues:
  Utility gas service                   $77,510   $69,816   $88,150
  Propane gas service                    11,444     8,990     8,900
                                       --------  --------   -------
     Total operating revenues            88,954    78,806    97,050
                                       --------  --------   -------
Operating expenses:
  Cost of gas sold                       44,941    39,961    55,130
  Operations and maintenance             21,660    21,046    21,800
  Depreciation and amortization           5,825     5,071     4,854
  Taxes other than income taxes           3,946     3,753     3,911
  Federal and state income taxes          3,635     1,972     2,616
                                       --------  --------   -------
     Total operating expenses            80,007    71,803    88,311
                                       --------  --------   -------
Operating income                          8,947     7,003     8,739
                                       --------  --------   -------
Other income (expense):
  Net rentals, service and
    appliance sales                         948       827       649
  Other, net                                (41)      607        (1)
                                       --------  --------   -------
        Total other income (expense)        907     1,434       648
 
Interest expense:
  Interest on long-term debt              3,004     3,161     3,285
  Other interest                            800     1,206       705
  Interest charged to construction          (28)      (34)      (25)
                                       --------  --------   -------
     Total interest expense               3,776     4,333     3,965
                                       --------  --------   -------
Net income                              $ 6,078   $ 4,104   $ 5,422
                                       ========  ========   =======
Weighted average shares outstanding       3,216     3,166     3,120
                                       ========  ========   =======
Earnings per share                      $  1.89   $  1.30   $  1.74
                                       ========  ========   =======
</TABLE>
                                
The accompanying notes are an integral part of these consolidated 
                      financial statements.
<PAGE> 22
<TABLE>
Consolidated Balance Sheets                          EnergyNorth, Inc.
<CAPTION>
(In thousands)
September 30,                                          1996      1995
---------------------------------------------------------------------
<S>                                                <C>       <C>
Assets
  Property:
     Utility plant, at cost                        $136,229  $129,895
     Accumulated depreciation and amortization       44,683    41,452
                                                   --------  --------
       Net utility plant                             91,546    88,443
     Net nonutility property, at cost                 7,748     7,989
                                                   --------  --------
       Net property                                  99,294    96,432
                                                   --------  --------
  Current assets:
     Cash and temporary cash investments                770       575
     Note receivable                                     39         -
     Accounts receivable (net of allowances of 
       $1,211 in 1996 and $950 in 1995)               2,029     2,171
     Unbilled revenues                                  582       586
     Deferred gas costs                               3,783         -
     Materials and supplies                           1,590     1,624
     Supplemental gas supplies                        9,039     8,074
     Prepaid and deferred taxes                       1,603     1,671
     Recoverable FERC 636 transition costs            1,733     1,733
     Prepaid expenses and other                       1,304     1,341
                                                   --------  --------
       Total current assets                          22,472    17,775
                                                   --------  --------
  Deferred charges:
     Regulatory asset - income taxes                  2,401     2,401
     Recoverable environmental costs                  6,840     3,741
     Other deferred charges                             996       988
                                                   --------  --------
       Total deferred charges                        10,237     7,130
                                                   --------  --------
Total assets                                       $132,003  $121,337
                                                   ========  ========
Stockholders' equity and liabilities
  Capitalization (see accompanying statements)     $ 74,738  $ 72,217
                                                   --------  --------
  Current liabilities:
     Notes payable to banks                           9,535     1,750
     Current portion of long-term debt                2,090     3,495
     Current portion of capital lease obligations       229       256
     Inventory purchase obligation                    7,867     7,130
     Accounts payable                                 6,189     4,768
     Deferred gas costs                                   -     5,645
     Accrued interest                                   838       874
     Accrued taxes                                    1,642       214
     Accrued FERC 636 transition costs                1,733     1,733
     Customer deposits, environmental and other       5,062     2,353
                                                   --------  --------
       Total current liabilities                     35,185    28,218
                                                   --------  --------
  Commitments and contingencies
  Deferred credits:
     Deferred income taxes                           16,525    15,180
     Unamortized investment tax credits               1,870     2,010
     Regulatory liability - income taxes              1,374     1,497
     Contributions in aid of construction and other   2,311     2,215
                                                   --------  --------
       Total deferred credits                        22,080    20,902
                                                   --------  --------
Total stockholders' equity and liabilities         $132,003  $121,337
                                                   ========  ========
</TABLE>
                                
                                
The accompanying notes are an integral part of these consolidated
                      financial statements.
<PAGE> 23
<TABLE>
Consolidated Statements of Capitalization       EnergyNorth, Inc.
<CAPTION>
(In thousands, except share information)
September 30,                                      1996      1995
-----------------------------------------------------------------
<S>                                            <C>       <C>
Capitalization:
  Common stockholders' equity:
     Common stock - par value of $1 per share,
       10,000,000 shares authorized; 3,239,148
       and 3,196,162 shares issued and
       outstanding in 1996 and 1995,
       respectively                             $ 3,239   $ 3,196
     Amount in excess of par                     30,342    29,583
     Retained earnings                           11,586     9,335
                                                -------   -------
          Total common stockholders' equity      45,167    42,114
                                                -------   -------
  Long-term debt:
     General and Refunding Bonds
       Due 2002                         8.67%     7,088     8,270
       Due 2009                         8.44%     4,333     4,667
       Due 2019                         9.70%     7,000     7,000
       Due 2020                         9.75%    10,000    10,000

     Mortgage notes payable
       Due 1996                         8.25%         -     1,628
       Due 1999                         8.75%     1,425         -
       Due 2008                         8.75%     1,013     1,063

     Notes payable
       Due through 2001       prime plus .50%       756       696
                                                -------   -------
                                                 31,615    33,324
     Less current portion                         2,090     3,495
                                                -------   -------
          Total long-term debt                   29,525    29,829
                                                -------   -------
  Capital lease obligations                         275       530
     Less current portion                           229       256
                                                -------   -------
          Total capital lease obligations            46       274
                                                -------   -------
Total capitalization                            $74,738   $72,217
                                                =======   =======
</TABLE>
                                
                                
The accompanying notes are an integral part of these consolidated
                      financial statements.
<PAGE> 24
<TABLE>
Consolidated Statements of
Common Stockholders'Equity                      EnergyNorth, Inc.
<CAPTION>


                                             Common stock                Total common
                                       $1.00    Amount in    Retained   stockholders'    
(In thousands,                           par       excess    earnings         equity        
except per share amounts)              value       of par
<S>                                   <C>         <C>          <C>           <C>          
Balance, September 30, 1993           $3,104      $28,229      $6,721        $38,054

Net income                                 -            -       5,422          5,422
Common stock
  - cash dividend ($1.08 per share)        -            -      (3,367)        (3,367)
Issuance of common stock under the
    Dividend Reinvestment and
        Stock Purchase Plan               38          631           -            669
                                      ------      -------     -------        -------    
Balance, September 30, 1994            3,142       28,860       8,776         40,778

Net income                                 -            -       4,104          4,104
Common stock
  - cash dividend ($1.12 per share)        -            -      (3,545)        (3,545)
Issuance of common stock under the
    Dividend Reinvestment and
        Stock Purchase Plan               54          723           -            777
                                      ------      -------      -------       -------
Balance, September 30, 1995            3,196       29,583        9,335        42,114

Net income                                 -            -        6,078         6,078
Common stock
   - cash dividend ($1.19 per share)       -            -       (3,827)       (3,827)
Issuance of common stock under the
    Dividend Reinvestment and
        Stock Purchase Plan               43          759            -           802
                                      ------       -------     -------       -------    
Balance, September 30, 1996           $3,239      $30,342      $11,586       $45,167
                                      ======      =======      =======       =======
</TABLE>


The accompanying notes are an integral part of these consolidated
                      financial statements
<PAGE> 25
<TABLE>
Consolidated Statements of Cash Flows           EnergyNorth, Inc.
<CAPTION>
(In thousands)
For the years ended September 30,                           1996       1995     1994
------------------------------------------------------------------------------------
<S>                                                     <C>         <C>      <C>             
Cash flows from operating activities:
    Net income                                          $  6,078    $ 4,104  $ 5,422
  Noncash items:
       Depreciation and amortization                       6,606      5,841    5,594
       Deferred taxes and investment tax credits, net      1,081      1,106    1,347

  Changes in:
     Accounts receivable, net                                103         90     (367)
     Unbilled revenues                                         4        (42)     (76)
     Inventories                                            (931)        (1)     716
     Prepaid expenses and other                               37       (115)     342
     Deferred gas costs                                   (9,428)       909    5,499
     Accounts payable                                      1,421        (80)     281
     Accrued liabilities                                    (287)      (253)    (102)
     Accrued/prepaid taxes                                 1,495       (403)    (599)
  Payments for environmental costs and other                (823)    (2,550)  (1,400)
                                                        ----------------------------
     Net cash provided by operating activities             5,356      8,606   16,657
                                                        ----------------------------
Cash flows from investing activities:
  Additions to property                                   (8,783)    (7,915)  (7,731)
                                                        ----------------------------
Cash flows from financing activities:
  Issues of common stock                                     802        777      669
  Issues of long-term debt                                 1,827        412      262
  Change in notes payable to banks                         7,785      1,750   (3,050)
  Increase in inventory purchase obligation                9,284      6,770    9,962
  Change in customer deposits and other                       88         13      120
  Cash dividends on common stock                          (3,826)    (3,545)  (3,367)
  Refunding requirements:
     Repayment of long-term debt                          (3,536)    (2,095)  (1,731)
     Repayment of capital lease obligations                 (256)      (272)    (264)
     Repayment of inventory purchase obligation           (8,546)    (6,974)  (9,655)
                                                        ----------------------------
     Net cash provided by (used for) financing activities  3,622     (3,164)  (7,054)
                                                        ----------------------------

Net increase (decrease) in cash and temporary
  cash investments                                           195     (2,473)   1,872
Cash and temporary cash investments, beginning of year       575      3,048    1,176
                                                        ----------------------------
Cash and temporary cash investments, end of year        $    770   $    575  $ 3,048
                                                        ============================
</TABLE>

The accompanying notes are an integral part of these consolidated
                      financial statements.
<PAGE> 26
ENERGYNORTH, INC.
Notes to Consolidated Financial Statements

Note 1.  Accounting Policies

The significant accounting policies followed by EnergyNorth, Inc.
and subsidiaries (the "Company") are set forth below.

Principles of Consolidation

The accompanying financial statements of the Company include the
accounts of all subsidiaries.  All significant intercompany
accounts and transactions have been eliminated in the
accompanying consolidated financial statements.

Business Organization

The Company's principal business activity is the management and
operation of a regulated gas distribution subsidiary located in
southern and central New Hampshire.  The rates and accounting
practices followed by the gas distribution subsidiary are
regulated by the New Hampshire Public Utilities Commission (the
"Commission"). The Company's accounting policies conform to
generally accepted accounting principles applicable to rate-
regulated enterprises and reflect the effects of the ratemaking
process in accordance with Statement of Financial Accounting
Standards ("SFAS") No. 71, "Accounting for Certain Types of
Regulation."

The Company also operates a nonregulated propane distribution
subsidiary and provides service and sells appliances through its
utility subsidiary.

Revenue Recognition

Utility revenues derived from the sale and transportation of
natural gas are based on rates authorized by the Commission.
Customers' meters are read and bills are rendered on a cycle
basis throughout the month.  The Company records unbilled 
revenues related to gas delivered but not billed at the end of 
the accounting period.

Cost of Gas Adjustment Clause

The Company's tariff includes a cost of gas adjustment ("CGA")
clause that permits billings to customers for changes in its cost
of gas over a base period cost.  The tariff provides for a CGA
calculation for a summer period and a winter period.  Any
difference between the cost of gas incurred and amounts billed to
customers is deferred for ratemaking and accounting purposes to
the next corresponding period.  Interest accrues on these amounts
at the prime rate, adjusted quarterly.

Inventories

Inventories are valued on the basis of the lower of average cost
or market.
<PAGE> 27
Depreciation

The Company provides depreciation on the straight-line basis.
The rates applied by the regulated subsidiary are approved by the
Commission.  Such rates were equivalent to a composite rate of
3.4% for each of the years ended September 30, 1996, 1995 and
1994.  The depreciation rates for nonregulated property, plant
and equipment were 8.2%, 7.8% and 8.0% for the years ended
September 30, 1996, 1995 and 1994, respectively.  Under
depreciation practices required by the Commission, when gas
utility assets under the composite method are retired from
service, the cost of the retired assets are removed from the
property accounts and charged, together with any cost of removal,
to the accumulated depreciation accounts.  For all other assets,
when assets are sold or retired, the cost of the assets and their
related accumulated depreciation are removed from the respective
accounts, net removal costs are recorded and any gain or loss is
included in income.

Deferred Charges

Total deferred charges consist primarily of regulatory assets and
the cost of issuing debt. The Company has established various
regulatory assets in cases where the Commission has permitted, or
is expected to permit, recovery of specific costs over a period
of time.  At September 30, 1996, regulatory assets include $6.8
million for environmental investigation and disposal costs and
$2.4 million of unrecovered deferred state income taxes (see Note 7).

The unamortized cost of issuing debt at September 30, 1996 is
$675,000.  Deferred financing costs are amortized over the life
of the related security.  Other deferred charges are amortized
over the recovery period specified by the Commission.

SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed of," issued in March
1995 and effective October 1, 1996, establishes accounting
standards for the impairment of long-lived assets.  SFAS No. 121
requires that any assets, including regulatory assets, which are
no longer probable of recovery through future revenues, be
revalued based on estimated future cash flows.  If the
revaluation is less than the book value of the asset, an
impairment loss would be charged to earnings.  While
circumstances may change, based on the current regulatory
environment in the Company's service area, it is not expected
that the adoption of SFAS No. 121 will have a material impact on
the Company's financial position or results of operations.

Investment Tax Credits

Investment tax credits are being amortized over the estimated
useful life of the property that gave rise to the credit.

Fair Value of Financial Instruments

Because of the short maturity of certain assets, which include
cash, temporary cash investments and accounts receivable, and
certain liabilities, which include accounts payable and notes
payable to banks, these instruments are stated at amounts that
approximate fair value.
<PAGE> 28
If long-term debt outstanding at September 30, 1996 was
refinanced using new issue debt rates of interest that on average
are lower than the outstanding rates, the present value of those
obligations would increase from the amounts outstanding on the
September 30, 1996 balance sheet by 10.8%.

Use of Estimates

The preparation of financial statements in conformity with
generally accepted accounting principles requires the use of
estimates and assumptions that affect assets and liabilities, the
disclosure of contingent assets and liabilities, and revenues and
expenses.  Actual amounts could differ from those estimates.

Reclassifications

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

Note 2.  Cash Flows
<TABLE>
Supplemental disclosures of cash flow information are as follows
(in thousands):
<CAPTION>
                                          1996      1995     1994
-----------------------------------------------------------------

<S>                                     <C>       <C>      <C>
Cash paid during the year for:
  Interest (net of amount capitalized)  $3,642    $4,415   $3,657
       Income taxes                        899     1,074    1,861

</TABLE>
In preparing the accompanying consolidated statements of cash
flows, all highly liquid investments having maturities of three
months or less when acquired were considered to be cash
equivalents.

Note 3.  Inventory Financing

The Company finances gas inventory purchases through the use of a
single purpose trust, which purchases gas with funds loaned to it
by a bank.  As the Company requires gas to service customers, gas
is repurchased from the trust at original product cost plus
financing costs and trust fees.  The cost of gas and related
financing are recoverable under the CGA.

The bank credit agreement provides for a .375% commitment fee on
the credit line and interest at prime (8.25% at September 30, 1996)
with a fixed rate interest option at less than prime on the
outstanding balance.  The trust agreement provides for a
management fee of $8,000 annually. The credit agreement between
the trust and the bank provides for a total commitment of up to
$9.5 million through February 1997.

As of September 30, 1996 and 1995, the gas inventories under the
trust agreement and controlled by the Company totaled $7.8
million and $7.1 million, respectively, and are included in
<PAGE> 29
inventories in the accompanying consolidated balance sheets.
Inventory purchase obligations under this financing agreement are
reflected as a current liability on the accompanying consolidated
balance sheets.

Note 4.  Notes Payable to Banks

As of September 30, 1996, the Company had available $13.0 million
under various unsecured bank lines of credit that are renewed
annually, $9.5 million of which was outstanding.  The weighted
average interest rate on borrowings outstanding on September 30,
1996 was 6.6%.  The lines bear interest at prime, or less than
prime on certain of the lines for fixed periods of time, and are
due on demand.  For some lines, the terms of the credit
agreements require annual commitment fees of .25% to .35% of the
lines.

Note 5.  Long-Term Debt

Interest payments for the General and Refunding Bonds are due
semi-annually.  The General and Refunding Bonds are
collateralized by first mortgage liens on substantially all real
property and operating plant facilities of the Company's gas
utility operations.
<TABLE>
The aggregate amounts of principal due for all long-term debt for
each of the five years subsequent to September 30, 1996 are as
follows (in thousands):
<CAPTION>
                        Fiscal year                        Amount
-----------------------------------------------------------------
                        <S>                                <C>
                        1997                               $2,090
                        1998                                2,035
                        1999                                2,706
                        2000                                1,662
                        2001                                1,601
</TABLE>
Note 6.  Common Stock

On June 6, 1990, the Board of Directors declared a dividend
distribution of one Right for each outstanding share of common
stock of the Company.  The Rights will not be exercisable until a
person ("Acquiring Person") or group of affiliated or associated
persons acquires 10% or more of the Company's outstanding common
stock or announces an intention to make a tender offer that would
result in ownership by such person or persons of 20% or more of
the Company's outstanding common stock.  Following such an event
and unless earlier redeemed or expired, each Right entitles its
holder to purchase from the Company one share of common stock for
$48.00.

In the event the Company is acquired in a merger or other
business combination, 50% or more of its consolidated assets or
earning power is sold or transferred, any person acquires 15% or
more of the Company's outstanding common stock, or an Acquiring
Person engages in one or more self-dealing transactions with the
Company, each Right will entitle its holder to purchase, at the
Rights' exercise price, a number of shares of common stock of the
Company or of the acquiring company having a value of twice such
<PAGE> 30
exercise price. Any Rights held by an Acquiring Person or its
affiliate or associate become null and void upon the occurrence
of any such events.

Prior to expiration of the Rights and except in certain instances
following acquisitions of 10% or more of the Company's common
stock, the Company may redeem all of the Rights for one cent per
Right.  The Rights do not carry voting or dividend rights and
have no dilutive effect or effect on the earnings of the Company.

The distribution of the Rights was made on June 18, 1990 to
shareholders of record on that date and attach to all common
shares issued at and after that date.  The Rights will expire on
June 18, 2000 unless such date is extended or unless the Rights
are earlier redeemed by the Company.

Note 7.  Income Taxes

On October 1, 1993, the Company adopted SFAS No. 109, "Accounting
for Income Taxes." SFAS No. 109 requires adjustments of deferred
tax assets and liabilities to reflect the future tax
consequences, consistent with currently enacted tax laws and
rates, of items already reflected in the financial statements.
The implementation of SFAS No. 109 on October 1, 1993 had no
material impact on the earnings or cash flows of the Company.  A
regulatory liability of approximately $440,000 was established
for the excess reserves for deferred taxes as a result of pre-
July 1, 1987 deferred income taxes that were recorded in excess
of the current Federal statutory income tax rate.  Also, a
regulatory liability of approximately $1,183,000 was established
for the tax benefit of unamortized investment tax credits, which
SFAS No. 109 requires to be treated as a temporary difference.
This benefit will be passed on to customers over the lives of the
property giving rise to the investment tax credits. The Company
does not believe that SFAS No. 109 will significantly impact
future results of operations  or cash flows based on current
ratemaking policy.

At September 30, 1996 and 1995, the SFAS No. 109 regulatory
liability amounted to $1.0 million and $1.1 million,
respectively, for the tax benefit of unamortized investment tax
credits, and $339,000 and $384,000, respectively, for the excess
reserves for deferred taxes as a result of pre-July 1, 1987
deferred income taxes that were recorded in excess of the current
Federal statutory income tax rate.

A deferred state income tax liability and a corresponding
regulatory asset of approximately $2.4 million, representing
revenues the Company expects to recover from utility gas service
customers, were established at September 30, 1994 as a result of
recording deferred state income taxes on the cumulative temporary
differences due to a change in New Hampshire tax law.  Effective
June 2, 1994, the 1% franchise tax assessed on sales of natural
gas was repealed.  Prior to the change in tax law, the franchise
tax was permitted as a credit against the New Hampshire Business
Profits Tax ("NHBPT").  Because franchise tax payments exceeded
the NHBPT, the Company's gas distribution subsidiary never
incurred a NHBPT liability; therefore, no deferred state income
taxes related to temporary differences were recorded.
<PAGE> 31
<TABLE>
The tax effects of cumulative differences that gave rise to the
deferred tax liabilities and deferred tax assets for the years
ended September 30, 1996 and 1995 were as follows (in thousands):
<CAPTION>
                                                     1996      1995
-------------------------------------------------------------------
<S>                                               <C>       <C>
Deferred tax assets:
  Contributions in aid of construction            $   696   $   666
  Unamortized investment tax credits                  636       683
  Allowance for doubtful accounts                     468       367
  Deferred gas costs                                    -     1,373
  Other                                               910       729
                                                  -----------------
    Total deferred tax assets                       2,710     3,818
                                                  -----------------
Deferred tax liabilities:
  Property-related                                 15,650    14,701
  Deferred gas costs                                1,773         -
  Environmental costs                               1,499     1,445
  Other                                             1,461     1,321
                                                  -----------------
      Total deferred tax liabilities               20,383    17,467
                                                  -----------------

Net deferred tax liability                        $17,673   $13,649
                                                  =================
<CAPTION>
Deferred income taxes were classified in the accompanying
consolidated balance sheets at September 30, 1996 and 1995 as
follows (in thousands):
                                                     1996      1995 
-------------------------------------------------------------------
<S>                                               <C>       <C>
Current                                           $ 1,148   $(1,531)
Long-term                                          16,525    15,180
                                                  -----------------
    Total                                         $17,673   $13,649
                                                  =================
<CAPTION>
The components of Federal and state income taxes reflected in the
accompanying consolidated statements of income for the years
ended September 30, 1996, 1995 and 1994 were as follows (in
thousands):
                                      1996      1995      1994
--------------------------------------------------------------
<S>                                 <C>       <C>       <C>
Federal:
  Current                           $  (32)   $1,090    $2,165
  Deferred                           3,165       625       539
  Investment tax credits              (140)     (141)     (145)
                                    --------------------------
      Total Federal                  2,993     1,574     2,559
                                    --------------------------
State:
  Current                              (65)      254        47
  Deferred                             707       144        10
                                    --------------------------
       Total state                     642       398        57
                                    --------------------------
Total provision for income taxes    $3,635    $1,972    $2,616
                                    ==========================
</TABLE>
<PAGE> 32
<TABLE>
The total Federal and state income tax provision, as a percentage
of income before Federal and state income taxes, was 37.4%, 32.5%
and 32.5% for the years ended September 30, 1996, 1995 and 1994,
respectively.  The following table reconciles the income tax
provision calculated using the Federal statutory tax rate of 34%
to the book provision for Federal and state income taxes (in
thousands):
<CAPTION>
                                          1996      1995      1994
------------------------------------------------------------------
<S>                                     <C>       <C>       <C>
Tax calculated at statutory rate        $3,302    $2,066    $2,733
Increase (reduction) in effective
 tax resulting from:
  Amortization of investment tax credit   (140)     (141)     (145)
  Adjustment due to change in tax rates    (28)      (28)      (28)
  State taxes, net of Federal tax benefit  424       266        38
  Other, net                                77      (191)       18
                                        --------------------------
Total provision for income taxes        $3,635    $1,972    $2,616
                                        ==========================
</TABLE>
Note 8.  Employee Benefit Plans

Pension Plans

The Company has noncontributory defined benefit plans covering
substantially all employees. Benefits are based on years of
credited service and average earnings during the five highest
consecutive years of earnings prior to the normal retirement
date.

The Company's funding policy is to annually contribute to the
plans an amount that is not less than the minimum amount required
by the Employee Retirement Income Security Act of 1974 and not
more than the maximum amount deductible for income tax purposes.

The Company also has a Supplemental Executive Retirement Plan
("SERP") for certain management employees.  Benefits are based on
the employee's service and earnings as defined in the SERP.  The
SERP is a non-qualified plan under the Internal Revenue Code and
has no advance funding. Benefit payments are made directly by the
Company to retired employees or their beneficiaries.
<TABLE>
Net periodic pension cost included the following components (in
thousands):
<CAPTION>
                                       1996       1995       1994
-----------------------------------------------------------------
<S>                                 <C>        <C>        <C>
Service cost for benefits earned    $   624    $   614    $   592
Interest cost on projected
   benefit obligations                1,193      1,138      1,073
Actual return on plan assets         (1,230)    (2,085)       542
Net amortization and deferral          (103)       885     (1,647)
                                    -----------------------------
Net periodic pension cost           $   484    $   552    $   560
                                    =============================
</TABLE>

<PAGE> 33
<TABLE>
<CAPTION>
The following table sets forth the funded status of the plans at
September 30, 1996 and 1995 (in thousands):
<S>                               <C>            <C>         <C>          <C>         
                                                        1996                     1995
                                                 Accumulated              Accumulated
                                        Assets      benefits      Assets     benefits
                                        exceed        exceed      exceed       exceed
                                   accumulated        assets accumulated       assets
                                      benefits    (unfunded)    benefits   (unfunded)
                                   -----------   ----------- -----------  -----------
Vested benefit obligation              $12,807       $ 1,017     $11,283     $    860
                                   ===========   =========== ===========  ===========
Accumulated benefit obligation         $13,336       $ 1,127     $11,804     $    947
                                   ===========   =========== ===========  ===========
Projected benefit obligation           $16,239       $ 1,645     $14,877     $  1,321
Plan assets at fair value               16,584             -      15,243            -
                                   -----------   ----------- -----------  -----------
Funded status                              345        (1,645)        366       (1,321)
Unrecognized transition
(asset) obligation                        (522)          375        (605)         437
Unrecognized prior service cost            622             7         709            -
Unrecognized net (gain)loss                777           280         376          (14)
Additional minimum liability                 -          (144)          -          (49)
                                   -----------   ----------- -----------  -----------
Prepaid pension (pension liability)    $ 1,222       $(1,127)    $   846     $   (947)
                                   ===========   =========== ===========  ===========

<CAPTION>
Assumptions used to determine the projected benefit obligation
were as follows:

                                                    1996          1995         1994
--------------------------------------------------------------------------------------
<S>                                             <C>           <C>          <C>
Discount rate                                       7.5%          7.5%         7.5%
Rate of increase in future compensation levels  4.0% - 5.5%   4.5% - 5.5%  4.5% - 5.5%
Expected long-term rate of return on assets         9.0%          9.0%         9.0%
</TABLE>
Plan assets are invested in common stocks and bonds.

The Company has employee 401(k) savings and investment plans
covering substantially all employees.  The Company made
contributions of $216,000, $210,000 and $178,000 for the years
ended September 30, 1996, 1995 and 1994, respectively.

Other Postemployment Benefits

In addition to providing pension benefits, the Company provides
certain health care and life insurance benefits to qualified
retired employees.

In accordance with SFAS No. 106, the Company began recording the
cost of postretirement benefits on an accrual basis in 1994.  The
expense recorded in fiscal 1996, 1995 and 1994 for providing
<PAGE> 34
postretirement benefits, including amortization of the
accumulated projected benefit obligation over a 20-year period,
was $588,000, $646,000 and $878,000, respectively.

The Company has funded these benefit costs by making cash
contributions, at the same level of expense recorded, to
voluntary employee benefit association ("VEBA") trusts
established separately for salaried and hourly paid employees.
<TABLE>
The following table sets forth the funded status of the plans at
September 30, 1996 and 1995 (in thousands):
<CAPTION>
                                                              1996      1995
----------------------------------------------------------------------------
<S>                                                        <C>       <C>
Accumulated postretirement benefit obligation as of July 31:
 Retirees                                                  $ 2,383   $ 2,217
 Fully eligible active plan participants                       933       904
 Other active participants                                   1,686     1,745
                                                           -------   -------
                                                             5,002     4,866
Plan assets at fair market value                            (1,704)   (1,193)
Unrecognized transition obligation                          (4,445)   (4,706)
Unrecognized net gain                                        1,319     1,209
                                                           -------   -------
Accrued postretirement benefit cost at July 31                 172       176
Contributions for the two-month period ending September 30     144       159
                                                           -------   -------
Accrued postretirement benefit cost at September 30        $    28   $    17
                                                           =======   =======
<CAPTION>
The components of net periodic postretirement benefit cost at
September 30, 1996 and 1995 are as follows (in thousands):
                                                                 1996    1995
-----------------------------------------------------------------------------
<S>                                                             <C>     <C>
Service cost-benefits attributed to services during the year    $ 143   $ 139
Interest cost on accumulated postretirement benefit obligation    358     347
Actual asset return                                              (104)   (149)
Net amortization and deferral                                     191     309
                                                                -----   -----
Net periodic postretirement benefit cost                        $ 588   $ 646
                                                                =====   =====
</TABLE>
An 11% average annual rate of increase in the per capita costs of
covered health care benefits was assumed for fiscal year 1996,
reduced in steps of 1% to a level of 5% at 2002 and thereafter.
This decrease results from changes in estimates of future health
care inflation, assumed changes in health care utilization and
related effects.  Increasing the assumed health care cost trend
rates by one percentage point in each year would have resulted in
a $434,000 increase in the accumulated postretirement benefit
obligation as of July 31, 1996 and an increase in the aggregate
of the service cost and interest cost components of net periodic
postretirement benefit cost for fiscal year 1996 of $37,000.  A
discount rate of 7.5% was used to determine the accumulated
postretirement benefit obligation.  The expected long-term rate
of return on plan assets is 9%. Plan assets are invested in
common stocks and bonds.

<PAGE> 35
Note 9. Commitments and Contingencies

Contracts

The Company has various contractual agreements covering the
transportation of natural gas, underground storage facilities and
the purchase of natural gas, which are recoverable under the
Company's CGA.  These contracts expire at various times from 1996
to 2011.

Litigation

The Company and its subsidiaries have been named in certain
lawsuits arising from normal operations.  In the opinion of
management, the outcome of these lawsuits will not have a
material adverse effect on the financial position or results of
operations of the Company.

Environmental Issues

The Company and certain of its predecessors owned or operated
facilities for the manufacture of gas from coal, a process used
through the mid-1900's that produced by-products that may be
considered contaminated or hazardous under current law, and some
of which may still be present at such facilities.  The Company
accrues environmental investigation and clean-up costs with
respect to former manufacturing sites and other environmental
matters when it is probable that a liability exists and the
amount or range of amounts is reasonably certain.

A former manufactured gas facility in Concord, New Hampshire has
been investigated and partially remediated.  Disposal of the
contents of the gasholder situated at this former gas
manufacturing facility has been completed.  Total remediation
costs amounted to approximately $3.5 million and were recorded in
deferred charges.  Recovery of costs from customers began on July
1, 1995 and will extend over a seven-year period.  The
unamortized balance of $3.0 million at September 30, 1996 is
excluded from rate base.

The New Hampshire Department of Environmental Services ("NHDES")
has selected a remedial action for a portion of the Concord site
at which wastes were disposed of between the late 1800's and 
mid-1900's.  The estimated cost of the remedial action ranges from
$2.9 million to $4.8 million, and the Company has recorded $2.9
million at September 30, 1996 in deferred charges.

The Company is pursuing recovery from its insurance carriers as
well as from insurance carriers of its predecessors with respect
to the Concord site.  In addition, the Company is pursuing
recovery against an entity that the Company alleges owned or
operated the manufactured gas plant during the late 1800's and
early 1900's.

The Company and another utility company have been directed by the
NHDES to conduct an environmental site characterization of a
former manufactured gas plant in Laconia, New Hampshire. The
Laconia manufactured gas plant operated between approximately
1887 and 1952, and the Company owned and operated the facility
for approximately the last seven years of its active life.
Without admitting liability, the Company and the other utility
have entered
<PAGE> 36
into an agreement under which costs of the site characterization
are shared.  The Company's share of the costs of  the site
characterization and a report to the NHDES, which is underway, is
expected to total $88,000 and has been recorded in deferred
charges as of September 30, 1996.  The Company is currently
unable to predict the magnitude of any liability that may be
imposed on it for the cost of additional studies or the
performance of a remedial action in connection with the Laconia
site.

The Company will pursue recovery from insurance carriers and
claims against any other responsible parties seeking to ensure
that they contribute appropriately to reimburse the Company for
any costs incurred with respect to environmental matters.  The
Company intends to seek and expects to receive approval of rate
recovery methods with respect to environmental matters after it
has determined the extent of contamination, received
recommendations with regard to remediation and commenced
remediation efforts.

Transition Costs

Federal Energy Regulatory Commission Order 636 allows interstate
pipeline companies to recover transition costs created, for the
most part, as they buy out of long-term, fixed-price gas
contracts. The Company's pipeline supplier, Tennessee Gas
Pipeline Company, began direct billing these costs to the Company
on September 1, 1993 as a component of demand charges. Through
September 30, 1996, the Company has been billed $5.9 million for
transition costs and has charged these costs to deferred gas
costs. The Company is recovering transition costs through the
CGA.  Based on current information, additional transition costs
are expected to range from $1.7 million to $5.1 million and will
continue to be billed over a period of approximately one to three
years.  At September 30, 1996, the Company has recorded an
estimated liability of $1.7  million for transition costs and a
corresponding regulatory asset.
<PAGE> 37
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and the Shareholders of EnergyNorth,
Inc.:

We have audited the accompanying consolidated balance sheets and
statements of capitalization of EnergyNorth, Inc. (a New
Hampshire corporation) and subsidiaries as of September 30, 1996
and 1995, and the related consolidated statements of income,
common stockholders' equity and cash flows for each of the three
years in the period ended September 30, 1996. These consolidated
financial statements and the schedule referred to below are the
responsibility of the Company's management.  Our responsibility
is to express an opinion on these financial statements and
schedule 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 financial statements referred to above
present fairly, in all material respects, the financial position
of EnergyNorth, Inc. and subsidiaries as of September 30, 1996
and 1995, and the results of their operations and their cash
flows for each of the three years in the period ended September
30, 1996, in conformity with generally accepted accounting
principles.

Our audit was made for the purpose of forming an opinion on the
basic consolidated financial statements taken as a whole.  The
financial statement schedule under part IV, Item 14, is presented
for purposes of additional analysis and is not a required part of
the basic consolidated financial statements. This information has
been subjected to the auditing procedures applied in our audit of
the basic consolidated financial statements and, in our opinion,
is fairly stated, in all material respects, in relation to the
basic consolidated financial statements taken as a whole.

 /s/ Arthur Andersen LLP

Boston, Massachusetts
November 1, 1996

<PAGE> 38
<TABLE>
   (b) Supplementary Financial Information
<CAPTION>
Selected Quarterly Financial Data (Unaudited)           EnergyNorth, Inc.
<S>                    <C>         <C>        <C>          <C>       <C>
(In thousands,         Operating   Operating  Net income   Earnings      Cash
except per share        revenues      income      (loss)     (loss)  dividend
amounts)                              (loss)              per share  paid per
                                                                        share
First Quarter
1996                     $25,976     $ 4,653    $ 3,751       $1.17      $.29
1995                      22,472       3,155      2,324         .74       .28
Second Quarter
1996                      39,661       7,379      6,671        2.07       .29
1995                      35,209       6,743      5,904        1.87       .28
Third Quarter
1996                      14,901      (1,104)    (1,693)       (.53)      .305
1995                      13,678        (717)    (1,487)       (.47)      .28
Fourth Quarter
1996                       8,416      (1,981)    (2,651)       (.82)      .305
1995                       7,447      (2,178)    (2,637)       (.83)      .28
</TABLE>
 Note:  Earnings (loss) per share are based on the weighted
 average shares outstanding at the end of the quarter.  In the
 opinion of the Company, the quarterly financial data include
 all adjustments, consisting of normal recurring adjustments and
 reclassifications, necessary for a fair presentation of such
 information.  Quarterly amounts vary significantly due to
 seasonal weather conditions.


ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
                 ACCOUNTING AND FINANCIAL DISCLOSURE

There were no such matters during the fiscal year ended September
30, 1996.


                            PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information called for by this Item is incorporated by
reference to pages 3 and 4 of the Registrants' Proxy Statement
for its Annual Meeting to be held February 5, 1997, except for
information relating to identification of Executive Officers of
the Registrant which is contained in Part I of the Report.


ITEM 11.  EXECUTIVE COMPENSATION

The information called for by this Item is incorporated by
reference to "Compensation of Directors," "Executive
Compensation" and "Non-Contributory Retirement Plan" on pages 5
through 7 of the Registrant's Proxy Statement for its Annual
Meeting to be held February 5, 1997.
<PAGE> 39
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
          MANAGEMENT

The information called for by this Item is incorporated by
reference to pages 2 and 3 of the Registrant's Proxy Statement
for its Annual Meeting to be held February 5, 1997.
     

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information called for by this Item is incorporated by
reference to "Compensation Committee Interlocks and Insider
Participation" on page 5 of the Registrant's Proxy Statement for
its Annual Meeting to be held February 5, 1997.
     
                            PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
             FORM 8-K

(a)  List of documents filed as part of this Report:

  (1)Financial Statements

     The following financial statements are included herein
     under Part II, Item 8.
                                                           Page No(s).
                                                        in this Report
Consolidated Statements of Income for the years ended
     September 30, 1996, 1995 and 1994                         21
Consolidated Balance Sheets at September 30, 1996 and 1995     22
Consolidated Statements of Capitalization at September 30,
     1996 and 1995                                             23
Consolidated Statements of Common Stockholders' Equity for
     the years ended September 30, 1996, 1995 and 1994         24
Consolidated Statements of Cash Flows for the years ended
     September 30, 1996, 1995 and 1994                         25
Notes to Consolidated Financial Statements                   26-36
Report of Independent Public Accountants                       37


<PAGE> 40
(2) Financial Statement Schedules

     The following supplementary financial statement schedules
     required by Rule 5-04 of Regulation S-X, and report thereon,
     are filed as part of this Form 10-K on the page indicated
     below:
         
Schedule                                                  Page No. in
Number   Description                                      this Report

II       Consolidated Valuation and Qualifying Accounts
           for the three years ended September 30, 1996       41
         Report of Independent Public Accountants             37

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

(3)      Exhibits Required by Item 601 of Regulation S-K

              See Exhibit Index on pages 43 through 45.

(b)      Reports on Form 8-K

         There were no reports on Form 8-K filed during the
     quarter   ended September 30, 1996.

(c)      Exhibits - See Exhibit Index on pages 43 through 45.

(d)      Financial Statement Schedules
<PAGE> 41
                                                      SCHEDULE II
                                
                                
                                
                        ENERGYNORTH, INC.
         CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
                         (In thousands)
  <TABLE>
  <CAPTION>
  Reserves which are deducted in the balance sheets
  from assets to that they apply:
  
                                                        Additions
                                                   ----------------------
   <S>          <C>                    <C>          <C>          <C>             <C>        <C>
   Year ended                          Balance at   Charged to   Charged to                   Balance
    September                           beginning    costs and        other                 at end of
          30,   Description             of period     expenses     accounts(1)   Deductions    period
   --------------------------------------------------------------------------------------------------
        1996    Allowance for
                doubtful accounts         $   950       $1,137         $143          $1,019    $1,211
        1995    Allowance for
                doubtful accounts           1,050          982          172           1,254       950
        1994    Allowance for
                doubtful accounts             890        1,307          149           1,296     1,050
                                                                                                       
  </TABLE>
  ________________________________________
   (1)  Represents recoveries on accounts previously written off
<PAGE> 42
                           SIGNATURES

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

                           ENERGYNORTH, INC.

Date:  December 20, 1996        by: /s/ Robert R. Giordano
                                Robert R. Giordano
                                President & Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the Registrant and in the capacities indicated on
December 20, 1996.
<TABLE>
<S>                                  <C>
/s/ Robert R. Giordano               Director, President and Chief
Robert R. Giordano                   Executive Officer (principal
                                     executive officer)

/s/ Michelle L. Chicoine             Vice President,Treasurer and Chief
Michelle L. Chicoine                 Financial Officer (principal
                                     financial officer)

/s/ David A. Skrzysowski             Vice President & Controller
David A. Skrzysowski                 (principal accounting officer)

/s/ Edward T. Borer                  Director
Edward T. Borer

/s/ N. George Mattaini               Director
N. George Mattaini

/s/ Constance B. Girard-diCarlo      Director
Constance B. Girard-diCarlo

/s/ Richard B. Couser                Director
Richard B. Couser

/s/ Sylvio L. Dupuis                 Director
Sylvio L. Dupuis

</TABLE>
<PAGE> 43
                           EXHIBIT INDEX
     
     The exhibits listed below are filed herewith, or are
     incorporated herein by reference to other filings.

         Exhibit
         Number                    Description

         3.1    Articles of Incorporation of EnergyNorth, Inc.
                are incorporated by reference to Exhibit 4.1 of
                EnergyNorth, Inc.'s Registration Statement on Form S-3,
                No. 33-41579, dated July 2, 1991.

         3.2    By-Laws of EnergyNorth, Inc., dated as of
                February 1, 1995, are incorporated by reference to
                Exhibit 4 to EnergyNorth, Inc.'s Post-Effective
                Amendment No. 2 to Registration Statement on Form S-3,
                No. 33-58127, dated November 21, 1996.

         4.1    Gas Service, Inc. General and Refunding Mortgage
                Indenture, dated as of June 30, 1987, as amended and
                supplemented by a First Supplemental Indenture, dated as
                of October 1, 1988, and by a Second Supplemental
                Indenture, dated as of August 31, 1989, is incorporated
                by reference to Exhibit 4.1 of EnergyNorth, Inc.'s Form
                10-K (File No. 0-11035) for the fiscal year ended
                September 30, 1989.

         4.2    Third Supplemental Indenture, dated as of
                September 1, 1990, to Gas Service, Inc. General and
                Refunding Mortgage Indenture, dated as of June 30, 1987,
                is incorporated by reference to Exhibit 4.2 of
                EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the
                fiscal year ended September 30, 1990.

         4.3    Fourth Supplemental Indenture, dated as of
                January 10, 1992, to Gas Service, Inc. General and
                Refunding Mortgage Indenture, dated as of June 30, 1987,
                is incorporated by reference to Exhibit 4.3 of
                EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the
                fiscal year ended September 30, 1992.

         4.4    Fifth Supplemental Indenture, dated as of February 1,
                1995, to Gas Service, Inc. General and Refunding
                Mortgage Indenture, dated as of June 30, 1987.

         4.5    Copies of Bond Indentures and a note and credit
                agreement defining the rights of holders of long-term
                debt of certain subsidiaries of EnergyNorth, Inc., under
                which the amounts of bonds or the note issued do not
                exceed 10% of the consolidated assets of EnergyNorth,
                Inc. will be furnished to the Securities and Exchange
                Commission upon request.

         4.6    Rights Agreement, dated as of June 18, 1990,
                between the Registrant and State Street Bank & Trust
                Company as Rights Agent is incorporated by reference to
                Exhibit I-2 to EnergyNorth, Inc.'s Registration
                Statement on Form 8-A, dated June 18, 1990.

<PAGE> 44
         10.1   Gas transportation agreement (FT-A), dated as of
                September 1, 1993, between Tennessee Gas Pipeline
                Company and EnergyNorth Natural Gas, Inc. is
                incorporated by reference to Exhibit 10.1 to
                EnergyNorth, Inc.'s Form 10-K  (File No. 0-11035) for
                the fiscal year ended September 30, 1993.

         10.2   Gas transportation agreement (contract No. 632),
                dated as of September 1, 1993, between Tennessee Gas
                pipeline Company and EnergyNorth Natural Gas, Inc. is
                incorporated by reference to Exhibit 10.2 of
                EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the
                fiscal year ended September 30, 1995.

         10.3   Supplemental Executive Retirement Plan of
                EnergyNorth, Inc., as amended.

         10.4   Deferred Compensation Agreement, dated as of
                November 30, 1993, between Robert R. Giordano and the
                Registrant is incorporated by reference to Exhibit 10.3
                to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for
                the fiscal year ended September 30, 1993.

         10.5   Deferred Compensation Agreement, dated as of
                November 30, 1993, between Albert J. Hanlon and the
                Registrant is incorporated by reference to Exhibit 10.5
                to EnergyNorth Inc.'s Form 10-K (File No. 0-11035) for
                the fiscal year ended September 30, 1993.

         10.6   Amendment to Deferred Compensation Agreement,
                dated as of October 1, 1996, between Robert R. Giordano
                and the Registrant.

         10.7   Amendment to Deferred Compensation Agreement,
                dated as of October 1, 1996, between Albert J. Hanlon
                and the Registrant.

         10.8   Deferred Compensation Agreement, dated as of
                November 30, 1993, between Richard P. Demers and the
                Registrant, as amended.

         10.9   Deferred Compensation Agreement, dated as of November
                30, 1995, between Frank L. Childs and the Registrant, as
                amended.

         10.10  Deferred Compensation Agreement, dated as of November
                30, 1993, between Michelle L. Chicoine and the
                Registrant, as amended.

         10.11  EnergyNorth, Inc. 1992 Directors' Deferred
                Compensation Plan, as amended.

         10.12  Consulting Agreement, dated as of October 12,
                1990, between N. George Mattaini and the Registrant is
                incorporated by reference to Exhibit 10.17 of
                EnergyNorth, Inc.'s Form 10-K  (File No. 0-11035) for
                the fiscal year ended September 30, 1990.

         10.13  Amendment No. 1 to  Consulting Agreement dated as
                of February 7, 1996 between N. George Mattaini and the
                Registrant.
<PAGE> 45
         10.14  Employment Agreement, dated as of December 1,
                1995, between Robert R. Giordano and the Registrant is
                incorporated by reference to Exhibit 10.9 of
                EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the
                fiscal year ended September 30, 1995.

         10.15  Employment Agreement, dated as of December 1,
                1995, between Albert J. Hanlon and the Registrant is
                incorporated by reference to Exhibit 10.11 of
                EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the
                fiscal year ended September 30, 1995.

         10.16  Management Continuity Agreement, dated as of
                December 7, 1995, between Robert R. Giordano and the
                Registrant is incorporated by reference to Exhibit 10.12
                of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for
                the fiscal year ended September 30, 1995.

         10.17  Management Continuity Agreement, dated as of
                December 7, 1995, between Albert J. Hanlon and the
                Registrant is incorporated by reference to Exhibit 10.14
                of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for
                the fiscal year ended September 30, 1995.

         10.18  Management Continuity Agreement, dated as of
                December 2, 1996, between Michelle L. Chicoine and the
                Registrant.

         10.19  Management Continuity Agreement, dated as of
                December 2, 1996, between Frank L. Childs and the
                Registrant.

         10.20  Management Continuity Agreement, dated as of
                December 7, 1995, between Richard P. Demers and the
                Registrant.

         10.21  EnergyNorth, Inc. Key Employee Performance and
                Equity Incentive Plan, as amended, is incorporated by
                reference to Exhibit 10.15 of EnergyNorth, Inc.'s Form
                10-K (File No. 0-11035) for the fiscal year ended
                September 30, 1995.

         21     Subsidiaries of the Registrant is incorporated by
                reference to Exhibit 22 of EnergyNorth, Inc.'s Form 10-K
                (File No. 0-11035) for the fiscal year ended September
                30, 1990.

         23     Consent of Arthur Andersen LLP.

         27     Financial Data Schedule of the Registrant.

         99     EnergyNorth, Inc.'s Dividend Reinvestment and
                Stock Purchase Plan, as amended is incorporated by
                reference to Exhibit 99 of EnergyNorth Inc.'s Post-
                Effective Amendment No. 2 to Registration Statement on
                Form S-3, No. 33-58127, dated November 21, 1996.