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, 1998
                Commission File Number   1-11441
                                
                        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.)

<TABLE>

<C>   <S>
1260 Elm Street, P.O. Box 329, Manchester, New Hampshire 03105-0329 (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 27, 1998, nonaffiliates held 3,214,581 shares of the registrant's $1.00 par value common
stock. On December 2, 1998, the aggregate market value of those shares was $92,017,381.

At the close of business on December 22, 1998, the registrant had 3,319,718 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
in connection with Annual Meeting to be held February 3, 1999.  Part III

</TABLE>

                       Page 1 of 49 pages.
          Exhibit Index appears on Pages 46 through 48.

<PAGE>
                        TABLE OF CONTENTS

Part I                                                               Page No(s).

Item 1.   Business                                               
            General                                                      4-5
            Utility Gas Distribution Business                            5-6
            Retail Propane Business                                       6
            Mechanical Contracting Business                               7
            Summary of Revenues                                           7
            Deregulation                                                 7-8
            Competition                                                   8
            Gas Supply                                                   
              General                                                     8
              Supply Contracts and Storage                                9
              Cost of Purchased and Produced Gas                         9-10
          Supervision and Regulation                                      10
          Employees                                                       10
          Executive Officers of the Registrant                            11
Item 2.   Properties                                                      12
Item 3.   Legal Proceedings                                             12-14
Item 4.   Submission of Matters to a Vote of Security Holders             14

Part II

Item 5.   Market for Registrant's Common Equity and Related
          Stockholder Matters                                             14
Item 6.   Selected Financial Data                                         15
Item 7.   Management's Discussion and Analysis of Financial Condition
          and Results of Operations                                      15-21
Item 7A.  Quantitative and Qualitative Disclosures About Management Risk   21
Item 8.   Financial Statements and Supplementary Data                    22-41
Item 9.   Changes in and Disagreements with Accountants on Accounting
          and Financial Disclosure                                         41

Part III

Item 10.  Directors and Executive Officers of the Registrant               41
Item 11.  Executive Compensation                                           41
Item 12.  Security Ownership of Certain Beneficial Owners and Management   42
Item 13.  Certain Relationships and Related Transactions                   42

<PAGE>
                  TABLE OF CONTENTS (continued)
<TABLE>                                
<C>                                                                         <S>   
Part IV                                                                     Page No(s).

Item 14.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K     42-44
Signatures                                                                       45
Exhibit Index                                                                  46-48
Exhibit 23 - Consent of Independent Public Accountants                           49

</TABLE>
<PAGE>
                                
                        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), ENI Mechanicals, Inc. (ENMI)
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. ENPI is headquartered at 75
Regional Drive, Concord, New Hampshire.  ENMI's wholly
owned subsidiaries, Northern Peabody, Inc. (NPI) and Granite
State Plumbing and Heating, Inc. (GSPH), are headquartered at
25 Depot Street, Manchester New Hampshire and 546 Mast Road,
Goffstown, New Hampshire, respectively.  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. ENPI is a
member of VGS Propane, LLC (VGSP), a Vermont joint venture with Northern
New England Gas Corporation.  VGSP is a limited liability company
which provides LP gas sales and service in the state of Vermont.

In May 1998, ENI acquired NPI and GSPH.  Both are mechanical
contractors engaged in the design, construction and service of
plumbing, heating, ventilation, air conditioning and process
piping systems. They serve commercial, industrial and
institutional customers in northern New England.  NPI has an
operating location in Portland, Maine.

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

The service territory of ENGI has a population of approximately
470,000 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
922 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.

<PAGE>

After three years of nonfarm employment growth rates greater than
both the New England average and the national average, the state
of New Hampshire nonfarm growth rate was 1.6% in 1998.  This
compares to a 2.4% average growth rate nationally and a 2.2%
average rate for New England for the same period.  However,
New Hampshire employment growth in 1999 is forecasted to be 2.4%.
New housing permits increased 15.4% in 1998 compared to 1997 and are
expected to increase another 5.4% in 1999.  While the New Hampshire
unemployment rate for 1999 is forecasted at 2.4% compared to 2.6%
in 1998, the labor force is forecasted to increase by 1.5% in
1999.  Job growth and low unemployment in the Company's service
area tend to result in an increase in volumes transported and
sold and numbers of customers.  (All employment and housing
statistics are taken from The New England Economic Project's
October 1998 Economic Outlook for New Hampshire.)  In fiscal
1998, the Company experienced net growth of more than 2.4% in
natural gas and transportation customers and approximately 6.8%
in propane customers over 1997.

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, while also expanding its system of mains into
areas in which there is a significant demand for natural gas
service.  ENGI has more than a 28% share of the home heating
market (based on households) 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 55% of the home
heating market. Currently, the price of natural gas for heating
is higher than the full-service price of fuel oil.  From a total
energy perspective, natural gas is a stronger competitor with a
complete line 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, they also provide opportunities for
expansion within the existing customer base.  Due to continued
customer conversions from other energy sources and expansion of
its service territory, ENGI 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 more than
2.3%.  This compares to an approximate 1.3% national average for
local distribution companies, according to the American Gas
Association. Additional growth in distribution operations also
occurs 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 has become more attractive. The
development of new gas-burning technologies for industry has
provided opportunities for increased gas usage in market sectors
that are not sensitive to the weather.

Utility Gas Distribution Business

ENGI distributes natural gas as a regulated utility pursuant to
franchise authority granted by the State of New Hampshire Public
Utilities Commission (Commission).  No operations are outside New
Hampshire.  While ENGI's franchise area is primarily residential
in character, 59% of sales volumes are commercial and industrial.
As of September 30, 1998, the Company's utility business served
nearly 69,600 customers, of which approximately 88% were
residential and 12% were commercial and industrial.  During
fiscal 1998, no ENGI customer purchased more than 4.2% of the
total ENGI annual sales and transportation volume.

<PAGE>

ENGI offers firm and interruptible transportation service to its
commercial and industrial customers. Transportation service
allows a customer to purchase a natural gas supply directly from
a third-party marketer.  The marketer delivers the gas supply to
one of  ENGI's interstate pipeline take stations. The customer
contracts with ENGI to transport the gas from the take station to
its facility.  To ensure a continual, uninterrupted supply, ENGI
also provides an optional, separate standby service as a backup
to the gas supplies of transportation customers.  As of September
30, 1998, ENGI had 66 firm transportation customers.

ENGI distributes gas to 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 more than 75% of New Hampshire's
natural gas customers.

On November 3, 1998, ENGI filed a petition with the Commission
for authority to operate in the city of Berlin, New Hampshire.
Berlin is a community of approximately 12,000 inhabitants in the
northern tier of the state.  The petition is supported by a
request from the State of New Hampshire Department of Corrections
to provide natural gas service to a new prison complex being
constructed in Berlin.  The prison will be located approximately
one-half mile from the Portland Natural Gas Transmission System.
ENGI anticipates additional development in the vicinity of the
prison complex, as well as interest from other energy users in
the city of Berlin.

Retail Propane Business

ENPI sells propane to more than 14,100 customers, of which
approximately 90% are residential and 10% are commercial and
industrial.  ENPI's service territory includes more than 150
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.
ENPI utilizes futures and fixed price contracts purchased on
the NYMEX to manage market risk associated with a portion of
anticipated gas supply requirements, but it does not use
derivative instruments for trading purposes.

ENPI holds a 49% interest in VGSP, a joint venture, and provides
planning and management expertise through its representation on
the VGSP Board of Managers.  In 1998, VGSP acquired Green
Mountain Propane Gas Company, creating the largest Vermont-based
propane company.  VGSP services more than 10,000 customers
throughout the state of Vermont.

<PAGE>

Mechanical Contracting Business

NPI and GSPH are mechanical contractors engaged in the design,
construction and service of plumbing, heating, ventilation, air
conditioning and process piping systems.  Both companies serve
commercial, industrial and institutional customers in northern
New England and Massachusetts from operating locations in
Manchester and Goffstown, New Hampshire and Portland, Maine.
Most mechanical systems are constructed on the site of each
project.  NPI performs some fabrication work, mostly for
industrial customers, at its fabrication shop in Manchester, New
Hampshire.  The total backlog of orders for NPI and GSPH at
September 30, 1998 was $16,197,000, all of which, except for
$5,207,000 is expected to be completed in fiscal year 1999.

Summary of Revenues

Revenues, in thousands of dollars, attributable to various
categories of gas distribution and related operations (unaudited)
during the last three fiscal years and mechanical contracting
operations for the five-month period ended September 30, 1998
(unaudited) are as follows:

                                               September 30,
                                      --------------------------------
                                          1998         1997       1996
                                      --------------------------------
Utility(natural gas)sales service     $ 82,686     $ 91,670    $76,007
Utility transportation service           2,610        1,308      1,503
Propane gas sales                       11,204       12,893     11,444
Service and appliance sales              2,128        2,185      1,917
Rentals                                    899          937        987
Contract sales                          13,426            -          -
                                      --------------------------------
                                      $112,953     $108,993    $91,858
                                      ================================

During the winter period, November 1 through March 31, the
Company's natural gas and propane revenues are substantially
higher than during the summer months.  The increase in natural
gas and propane revenues during the winter, and the concomitant
increase in gas supply requirements, occurs because approximately
90% of ENGI's and ENPI's customers use natural gas and propane
for heating.

Deregulation

ENGI has been providing gas transportation rates and separate
standby and balancing services for commercial and industrial
customers since late 1993.

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, 1998, ENGI had 66 firm transportation customers.
These customers are, for the most part, large commercial and
industrial customers.  The volume transported for firm
transportation customers in fiscal 1998 was 1.5 Bcf,
approximately  13% of ENGI's total gas delivered.  ENGI is
participating in a proceeding at the Commission to examine
further unbundling of the natural gas industry in New Hampshire.
The purpose of the proceeding is to determine whether and to what
extent unbundling provides benefits to customers and to make
recommendations to the Commission as to the advisability of
further unbundling to other classes of

<PAGE>

customers.  Recommendations to the Commission are not expected until
late summer of 1999. ENGI cannot predict the outcome of the
proceeding or the impact on transportation volumes or
customers.  ENGI expects the number of transportation
customers and the volume of gas transported to increase.

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.

Under current market conditions, natural gas has a significant
price advantage over electricity in New Hampshire.  Natural gas
heating costs are currently less than one-third of electric
heating costs.  At the present time, the price of natural gas for
heating is higher than the full-service price of fuel oil. ENGI
continues to add customers who might otherwise elect to use oil,
because energy decisions are also based on factors other than
cost, such as service, cleanliness and environmental impact.
Demand for natural gas is expected to continue to increase as
national attention remains focused on its environmental
advantages, efficiency and security of supply. 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 numerous 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.

The mechanical contracting market is very competitive.  Contracts
are awarded through a bid process in which there are, usually, at
least three bidders.  The principal competitive factors are price
and the quality and reliability of the construction work.

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 Dekatherms

<PAGE>

("Dths," a unit of heating value equivalent to one million
British Thermal Units) per day on a firm transportation basis
with an additional 8,000 Dths per day on an interruptible basis.
ENGI also contracted with a New England supplier for city gate
delivery of 8,000 Dths per day (151 day service). Natural gas
supplies are purchased with both long-term and short-term firm
contracts.  During fiscal year 1998, ENGI purchased approximately
1.8% of its annual natural gas requirements with short-term
contracts.  ENGI did not purchase supply on the spot market in
fiscal year 1998.  ENGI's long-term contracts, under which it has
firm supply for approximately 40,529 Dths per day, have remaining
terms of one to eight years.

In fiscal 1998, approximately 56% of the gas delivered by ENGI
came from domestic pipeline sources, 19% from Canadian pipeline
supplies and approximately 11% from supplemental pipeline
supplies. LP and liquefied natural gas (LNG) purchases from both
domestic and foreign sources made up approximately 1% of the gas
delivered by ENGI.  Supplemental supplies of gas are produced
from plants owned and operated by ENGI.  Third-party marketer
supply to end users on ENGI's system accounted for 13%.

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 115,660 Dths of LP and 13,057 Dths of LNG.

ENGI has contracted for 300,000 Dths of supplemental gas vapor,
100,000 Dths of LNG and an additional one million gallons of LP
for the winter of 1998 - 1999.

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

Cost of Purchased and Produced Gas.  The average unit cost of gas
purchased and produced during the twelve months ended
September 30, 1998 was approximately $4.09 per Mcf compared to $4.28 per
Mcf for the same period last year.  The 1998 average unit cost
reflects the lower 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 (or requires refunds
to its customers) of gas costs (including pipeline, LP, LNG and
storage) that are higher (or lower) than the cost of gas included
in base rates. ENGI may adjust the approved CGA rate upward or
downward on a monthly basis.  The monthly accumulative
adjustments may not exceed 10% of the approved unit cost of gas
sold. Amounts recovered through CGA rates are reconciled twice
annually against actual costs, for summer and winter periods, and
future CGA rates are adjusted accordingly.

<PAGE>

ENGI has a Natural Gas Price Risk Management Program designed to
protect customers from sharp increases in the commodity cost of
gas.  Under the program, ENGI has purchased call and sold put 
options for the 1998 - 1999 winter period.  The call options
provide the right, but not the obligation, to purchase gas at a
predetermined price by a certain date.  By selling a put option,
the Company agrees to purchase gas at a predetermined price by a
certain date.  The purchase of call options and the sale of put
options creates a collar mechanism.  The collar establishes a
maximum and minimum price at which the Company will buy gas
contracts on the commodities market.  All program costs and
benefits will be passed on to customers through the CGA.

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 fuel inventory trust, including
administration fees and carrying costs, are recovered through the
CGA.

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 a 30-day notice to the
Commission, which has the power to suspend, investigate and
change any proposed increase in rates and charges.

The natural gas and propane 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.  Their capital expenditures,
earnings and operations have not been materially affected by
environmental and local regulation.

The mechanical contracting businesses of NPI and GSPH are subject
to OSHA regulations and local, state and federal building codes
but are not otherwise subject to direct regulation by federal,
state and local agencies.

Employees

At September 30, 1998, the Company had 421 full-time employees,
of whom 138 were represented by four contracts with Local 12012
of the United Steelworkers of America.  The contracts expire in
2001 and 2002.  Various locals of the United Association of
Plumbers and Pipefitters represent 96 employees under a contract
that expires in 2000.

<PAGE>

<TABLE>
<CAPTION>
Executive Officers of the Registrant

The executive officers of the Registrant are listed below, together with age at December 22, 1998,
position and other information as to each.  The term of office of each executive officer terminates
when his or her successor has been duly elected and qualified.

<C>                               <S>          <S>           <S>   
                                               Served as       Principal Occupations and Employment During  
Name and Position                               Officer                  Last Five Years Other Than
with the Registrant                Age           Since                        with the Registrant
--------------------------------------------------------------------------------------------------------------
Robert R. Giordano                 60            1982        Chairman and Chief Executive Officer of ENGI; 
  President and Chief                                        formerly (until 1998) President and Chief 
  Executive Officer                                          Executive Officer of ENGI; Chairman and Chief
                                                             Executive Officer of ENPI; Chairman, President
                                                             and Chief Executive Officer of ENMI.

Michelle L. Chicoine               42            1990        President of ENGI; formerly (1996-1998) Senior   
  Executive Vice President                                   Vice President, Treasurer and Chief Financial
                                                             Officer, formerly (1993-1997) Vice President of
                                                             ENGI.

Frank L. Childs                    54            1995        Senior Vice President, Treasurer and Chief
  Senior Vice President,                                     Financial Officer of ENGI; formerly (1997) 
  Treasurer and Chief                                        Senior Vice President, formerly (1995-1997) Vice  
  Financial Officer                                          President of ENGI; formerly (1992-1994)
                                                             Executive Vice President and Chief
                                                             Administrative Officer of UNITIL Corporation, a
                                                             registered public utility holding company;
                                                             formerly (until 1994) President of Fitchburg Gas
                                                             and Electric Light Company, a public utility.

Kenneth M. Margossian              50            1998        Executive  Vice President of ENGI; formerly  
  Senior Vice President                                      (1998) Senior Vice President of ENGI; formerly
                                                             (until 1997) President and Chief Operating Officer
                                                             of Commonwealth Gas Company, a natural gas
                                                             distribution company.

Richard P. Demers                  62            1988        Vice Chairman of ENPI; formerly (1993-1998)  
  Vice President                                             President of ENPI; Vice President of ENGI.

David A. Skrzysowski               52            1983        Vice President and Controller of ENGI.
  Vice President and Controller

Stephen W. Smith                   51            1997        Vice  President of ENGI; formerly (1993-1996)  
   Vice President                                            Director of Human Resources of Hampshire
                                                             Chemical Corporation.

</TABLE>
<PAGE>

ITEM 2.  PROPERTIES

The Company's utility gas distribution facilities constitute the
majority of its physical assets.  As of September 30, 1998, ENGI
had approximately 1,086 miles of mains and 690 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.

Substantially all of the Company's utility properties are subject
to the liens of the indentures securing the ENGI First Mortgage
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 computer equipment.

Office/operating locations for NPI and GSPH in Manchester and
Goffstown, New Hampshire and Portland, Maine are leased until
2002-2003 with options to renew.  The locations are adequate and
are regularly maintained and in good condition.  Substantially
all vehicles and other equipment are leased or are subject to
purchase money security interests held by banks.

ITEM 3.  LEGAL PROCEEDINGS

In addition to the matters described below, the Company is a
party in several proceedings of the sort that arise in the ordinary
course of its business.  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. The Company
is a party to various routine Commission proceedings relating to
operations, none of which is expected to have a material impact
on the Company's earnings or assets.

The Company and certain of its predecessors owned or operated
several facilities for the manufacture of gas from coal, a
process used through the mid-1900s 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 cleanup 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 can be reasonably estimated.

The New Hampshire Department of Environmental Services (NHDES)
has required remedial action for a portion of the Concord site at
which wastes were disposed from approximately 1852 through 1952.
The estimated cost to complete this remedial action ranges from
$1.9 million to $4.0 million,

<PAGE>

and the Company has recorded $1.9 million at September 30, 1998 in
deferred charges.  The Company has received an order from the Commission
approving recovery from customers, over a seven-year period, of
substantially all costs, excluding carrying costs, of past and future
investigation, remediation and recovery efforts for the Concord site.
Recovery of costs incurred through April 30, 1998 began on June 1, 1998.
The total unamortized balance for the Concord site, including the
gasholder site, of $5.5 million at September 30, 1998 is excluded
from rate base.  The Company may not earn a return or charge
rates to customers based on amounts not included in rate base.

The Company has instituted several lawsuits to recover the costs
of investigation and remediation of the Concord site.  On
December 8, 1995, the Company 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 and National Union Fire Insurance
Company, later adding Columbia Casualty Company as a defendant,
seeking declaratory judgment that they owe the Company a
defense and/or indemnification for environmental claims
associated with the Concord facility.  The Company 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 the Company a defense and/or
indemnification for environmental claims associated with the
Concord facility.

At the direction of NHDES, the Company and Public Service Company
of New Hampshire (PSNH), an electric utility company, conducted 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
PSNH entered into an agreement under which the costs of the site
characterization were shared. The Company's share of the costs of
the site characterization and a report to the NHDES totaled
$409,000 and has been recorded in deferred charges as of
September 30, 1998.  The report describes conditions at the site,
including the presence of by-products of the manufactured gas
process in site soils, groundwater and sediments in an adjacent
water body. Based upon its review of the report, the NHDES has
directed PSNH and the Company to prepare and submit a remedial
action plan.  The Company has recorded an additional $150,000 in
deferred charges at September 30, 1998, for risk characterization
studies at the Laconia site and a remedial action plan. The
Company expects to incur further costs but 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
commenced proceedings in New Hampshire Superior Court and Federal
District Court on February 2, 1997 against eighteen of its
present and former insurers seeking recovery of expenses that
have been and will be incurred in connection with the
investigation and remediation of contamination from the Laconia
plant.

Through November 1998, the Company reached settlements with
defendants in gasholder related environmental lawsuits in an
aggregate amount of $3.5 million and further payment to the
Company of a portion of future Concord site remediation costs.
The Company expects that such settlement amounts will reduce the
amount that it will be permitted by the Commission to recover
from its ratepayers.

During 1998, the Company received a notice of potential
responsibility from the Environmental Protection Agency related
to a site in the area of its former gas manufacturing plant in
Nashua, New Hampshire.  The Company's share of costs for the
disposal of contaminants at the site are estimated to range from
$300,000 to $350,000 and the Company recorded $300,000 in
deferred charges at

<PAGE>

September 30, 1998.  The Company subsequently
received a request from the NHDES to investigate the former gas
manufacturing site in Nashua, New Hampshire.  The Company expects
to incur cost but is currently unable to predict the magnitude of
any liability that may be imposed on it for cost of studies or
the performance of remedial action in connection with the Nashua
site.

The Company is pursuing and intends to 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.

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 1998.

                            PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
                 STOCKHOLDER MATTERS

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 1998 and 1997 were as follows:

                             Fiscal 1998             Fiscal 1997
                         High        Low         High        Low
----------------------------------------------------------------
First Quarter       $28 13/16    $22 3/4      $22 1/8    $19
Second Quarter       29  1/16     27 5/8       22 1/4     20 3/4
Third Quarter        29  3/4      26 3/8       22 5/8     21 1/4
Fourth Quarter       27  5/8      25 1/4       23 1/4     22


As of December 2, 1998, there were 2,019 holders of record of common stock.

Quarterly cash dividends paid were as follows:

                             Fiscal 1998             Fiscal 1997
----------------------------------------------------------------
First Quarter                      $.32                    $.305
Second Quarter                      .32                     .305
Third Quarter                       .335                    .32
Fourth Quarter                      .335                    .32

<PAGE>

<TABLE>
<CAPTION>

ITEM 6.  SELECTED FINANCIAL DATA

(In thousands, except per share amounts)
                                                            1998      1997      1996      1995      1994
                                                        ------------------------------------------------
<C>                                                     <S>       <S>       <S>       <S>       <S>
Total operating revenues                                $109,926  $105,871  $ 88,954  $ 78,806  $ 97,050
                                                                                                         
Net income                                                 5,378     6,518     6,078     4,104     5,422
                                                                                                        
Earnings per share                                          1.64      2.01      1.89      1.30      1.74

Cash dividends per share                                    1.31      1.25      1.19      1.12      1.08
                                                                                                      
Total assets                                             155,150   139,445   132,746   121,337   121,019
                                                                                                        
Capitalization:                                                                                      
  Common stockholders' equity                             50,890    47,722    45,167    42,114    40,778
  Long-term debt (including capital lease obligations)    44,390    45,242    29,571    30,103    33,501
                                                        ------------------------------------------------
    Total capitalization                                $ 95,280  $ 92,964  $ 74,738  $ 72,217  $ 74,279
                                                        ================================================                        
Short-term debt (including current portion of                                                       
  long-term debt)                                       $  5,585  $  1,078  $ 11,854  $  5,501  $  2,308
_______________
Reclassifications are made periodically to previously issued financial data to conform to the current presentation.

</TABLE>

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
                CONDITION AND RESULTS OF OPERATIONS

Earnings and Dividends

Earnings per share in 1998 were $1.64 compared to $2.01 in 1997.
Warmer weather in the Company's service territory significantly
impacted net income, which declined to $5.4 million in 1998 from
$6.5 million in 1997.  Temperatures were 12.9% warmer than normal
and 11.4% warmer than the prior year.  The effect of weather,
when compared to normal, reduced 1998 utility margin by $.51 per
share after taxes; whereas, warmer temperatures in 1997 decreased
utility margin by $.14 per share after taxes.  In addition, 1997
earnings were $.20 per share higher than 1998 as a result of a
favorable net property tax settlement that was recorded in 1997.
Partially offsetting the 1998 decrease in net income was
continued customer growth and successful efforts to contain
operating costs.  The earnings represent a return on average
common equity of 10.9%.

Cash dividends paid on common stock were $1.31, representing a
payout ratio of 80% of 1998 earnings. The Company's Board of
Directors continued its commitment to provide an attractive
return to shareholders by increasing the quarterly dividend
during the fiscal year. The current quarterly dividend of 33.5
cents per share is equal to an annual dividend of $1.34 per
share, a 4.7% increase over 1997 dividends.

<PAGE>

Utility Sales and Revenues

The rates charged to utility customers are regulated by the
Commission.  The Commission is required by New Hampshire law to
allow the Company to charge rates that are just and reasonable,
such that the Company is compensated for the cost of providing
service and allowed a reasonable rate of return on its
investment.  The Company regularly assesses whether it is earning
a reasonable return and files for rate increases when it
determines that it is not being permitted to earn a reasonable
return.

The Company generates revenues primarily through the sale and
transportation of natural gas. The Company's gas sales are
divided into two categories:  firm, whereby the Company must
supply gas to customers on demand; and interruptible, whereby the
Company may, generally during colder months, temporarily
discontinue service to high-volume commercial and industrial
customers. Sales of gas to interruptible customers do not
materially affect the Company's operating income because all
margin on such sales is returned to the Company's firm customers.

The Company's tariff includes CGA rates that 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 through CGA
rates are reconciled at least semiannually against actual costs,
and future CGA rates are adjusted accordingly.

The Company's sales are responsive to colder weather because the
majority of firm customers use natural gas for space heating
purposes.  The Company measures weather through the use of degree
days.  A degree day is calculated by subtracting the average
temperature for the day from 65 degrees Fahrenheit.  The "normal"
number of degree days during any period is calculated based upon
a rolling approximate 30-year average number of degree days
during such period. The table below discloses degree day data as
recorded at the U.S. weather station in Concord, New Hampshire,
comparing actual degree days to the previous period and to
normal.  Because of the size and topographical variations of the
Company's service territory, weather conditions within such
territory often vary.  The Company considers Concord, New
Hampshire weather data to be representative of weather conditions
within its service territory.

<TABLE>
<CAPTION>
                                            Degree days
                                      ----------------------
                                               Prior           Change vs.   Change vs.
                                      Actual  period  Normal  prior period    normal
                                      ------------------------------------------------
<C>                                    <S>     <S>     <S>       <S>          <S>      
Fiscal year ended September 30, 1998   6,532   7,373   7,499     (11.4)%      (12.9)%
Fiscal year ended September 30, 1997   7,373   7,482   7,506      (1.5)%       (1.8)%
Fiscal year ended September 30, 1996   7,482   6,834   7,549       9.5%         (.9)%

</TABLE>

Operating revenues for EnergyNorth Natural Gas, Inc., the
Company's regulated gas distribution subsidiary, were $85.3
million in 1998 compared to $93 million in 1997, an 8.3%
decrease.  Firm sales gas revenues in 1998 were $78.8 million
compared to $85.7 million in 1997.  Firm transportation revenues
of $2.4 million were twice the level achieved in 1997.  The weather in

<PAGE>

1998 was 12.9% warmer than normal and 11.4% warmer
than the previous year.  Growth in the average number of
customers of 2.4% in 1998 helped mitigate the effects of the
warmer temperatures.  Firm sendout, including transportation, was
11.6 Bcf compared to 11.5 Bcf in 1997. Volumes transported
increased more than 121%.  This increase included a shift of
207,000 Mcf from firm commercial and industrial sales to
transportation, representing a decrease of $900,000 in operating
revenues attributable to the commodity cost of 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
customers by their marketers.  The Company's rate structure
provides for transportation service margin that is approximately
2.4% less than sales service margin.  At September 30, 1998, the
Company had 66 firm transportation customers compared to 45
customers the previous year.

The Company is currently involved in a proceeding at the
Commission to examine further unbundling of the natural gas
industry in New Hampshire.  The Company cannot predict the
outcome of this proceeding or potential impact on operating
income.

Utility Cost of Gas Sold

The cost of gas sold was $46.7 million in 1998 compared to $54.6
million in 1997.  The decrease was primarily due to lower volumes
of gas sold ($6.1 million) and a decline in the unit cost ($2.4
million).  The average unit cost of gas sold in 1998 was $4.09
per Mcf compared to $4.28 per Mcf in 1997.  Decreases or
increases 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

Net income for 1998 for EnergyNorth Propane, Inc., the Company's
retail propane operation, was $201,000, a 57% decrease from 1997.
In March 1998, the Company's retail propane joint venture in
Vermont acquired Green Mountain Propane Gas Company.  Since,
typically, third and fourth quarter results show losses because
of the seasonal use of gas, the timing of the acquisition
contributed to a 1998 after-tax loss of $244,000 from the joint
venture.  The average number of retail propane customers
increased more than 7% in 1998.  Despite substantial customer
growth, propane gallons sold were slightly less than 1997 due to
the warmer weather.  While 1998 operating revenues of $11.2
million were $1.7 million less than 1997, there was no change in
gross margin. The Company was able to maintain a competitive
price while the unit cost of gas sold decreased more than 22%.
Operations and maintenance expense increased $186,000, or almost
5.2%, as a result of increases in sales expense to support an
effective marketing program and increases in wages and wage-
related benefits.

Mechanical Contracting Operations

The Company's mechanical contracting operations were acquired
under the purchase method of accounting in May 1998.
Consequently, five months of ENI Mechanicals, Inc. operations are

<PAGE>

included in fiscal year 1998 results, with no restatement for the
prior year.  Contract revenues and operating income for the five
months ended September 30, 1998 were $13.4 million and $231,000,
respectively.

Operating Expenses

Operations and maintenance expense for fiscal year 1998 included
the expenses of the mechanical contracting operations that were
acquired in May 1998.  The increase from 1997 was due mostly to
this acquisition, and operations and maintenance expense would
otherwise have been essentially unchanged from the prior year.
The warmer winter season resulted in lower maintenance and bad
debt expenses. Other operating and administrative costs decreased
as a result of effective cost containment efforts, which offset
increases in labor costs and health insurance and other employee
benefit costs.

Depreciation and amortization expense increased 7.3% in 1998 and
reflects continued expansion, including the full impact of the
Company's major main extension to serve Milford, New Hampshire,
which was completed in late fiscal year 1997.  Depreciation and
amortization expense also includes normal upgrades to the
distribution system and related facilities and amortization of
environmental remediation costs. Net additions to property, plant
and equipment were $14.7 million and $13.3 million in 1998 and
1997, respectively.

Taxes other than income taxes increased almost $1.2 million to
$4.1 million in 1998.  The 1997 results include a favorable
property tax settlement, net of adjustments, of more than $1
million.

The lower level of pretax income is the main reason for the
$706,000 decrease in federal and state income taxes in 1998.

Capital Resources and Liquidity

Because of the seasonal nature of the Company's gas operations, a
substantial portion of cash receipts is generated during the
November - March heating season, which results in the highest
cash inflow during late winter and early spring.  Cash
requirements for capital expenditures, dividends, long-term debt
retirement, environmental remediation 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.

The Company's major uses of cash in 1998 were capital
expenditures of $14.7 million, environmental remediation of
$661,000, additional investment of $1.8 million in the joint
venture for the purchase of Green Mountain Propane Gas Company,
and retirement of $1.3 million of long-term debt.  In addition,
dividend payments to shareholders totaled $4.3 million in 1998.
These expenditures were funded primarily through cash generated
from current operations and short-term borrowings.  Borrowings against
lines of credit during 1998 ranged from zero to a high of $3.6 million.
In addition, at September 30, 1998, deferred gas cost was in an

<PAGE>

overcollected position resulting from winter and summer activity.
The overcollected amounts will be returned to customers through the
CGA mechanism.

Capital expenditures for 1999 are currently projected at
approximately $13.4 million.  Additional cash requirements will
be necessary for the payment of dividends, environmental
remediation, annual sinking fund requirements and maturities of
long-term debt 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, 1998, the Company
had available lines of credit aggregating $26.2 million, $3.5
million of which was outstanding.  In addition, a credit line of
$10.5 million was available at September 30, 1998, under the
Company's fuel inventory trust financing plan.  At September 30,
1998, the Company's fuel inventory in trust in the consolidated
balance sheet was $8.7 million with an outstanding purchase
obligation of $8.7 million.

On September 30, 1998, the Company's capitalization ratio
consisted of 50.5% common equity and 49.5% debt, including short-
term debt.

Environmental Matters

The Company continues to work with federal and state
environmental agencies to assess the extent and environmental
impact of contaminants that may exist at or near former gas
manufacturing sites. The costs of such assessments and any
related remediation determined to be necessary is expected to be
funded from traditional sources of capital, recoveries from
insurance carriers and responsible third parties and customers.
For further information, see Note 11 to the consolidated
financial statements.

Results of Operations 1997 Compared to 1996

Net income increased to $6.5 million in 1997 from 1996 net income
of $6.1 million.  Earnings per share in 1997 were $2.01 compared
to $1.89 in 1996. The 1997 increase in earnings was due primarily
to successful efforts to contain operating costs.

Operating revenues were more than $105 million in 1997, an
increase of 19% from 1996.  Utility gas service revenues, which
represented more than 87% of total operating revenues, increased
by $15.5 million, or 20%.  The increase resulted primarily from
higher CGA rates.  The average unit cost of gas sold in 1997 was
$4.28 per Mcf compared to $3.96 per Mcf in 1996.  Weather in the
Company's service territory was 1.5% warmer than 1996, although
the November - March winter heating season was 7.3% warmer.  The
total volume of gas delivered to utility customers increased more
than 2%. Partially offsetting the impact of the warmer
temperatures was the 2.2% growth in the average number of utility
customers.

Propane operations recorded $12.9 million in total operating
revenues in 1997, an increase over 1996 of $1.5 million.  The
increase was due primarily to an 8% increase in the average
number of propane customers and a 25% increase in the unit cost
of propane gallons sold.

<PAGE>

Operations and maintenance expense was approximately the same as
the prior year.  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.

Taxes other than income taxes decreased $1.1 million to $2.9
million, due primarily to a favorable property tax settlement,
net of adjustments, of more than $1 million, which offset
property tax rate increases and additions to taxable property.

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 changes in the cost
of gas and of the CGA mechanism on total margin; projected
capital expenditures and sources of cash to fund expenditures;
impact of unbundling regulatory proceedings; year 2000 readiness;
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 regulatory allowance of recovery of changes
in the cost of gas; uncertain demands for capital expenditures
and the availability of cash from various sources; uncertainty as
to whether transportation rates will be reduced in future
regulatory proceedings with resulting decreases in transportation
margins; uncertainty as to environmental costs and as to
regulatory approval of the full recovery of environmental costs,
transition costs and other regulatory assets; weather; results of
regulatory proceedings on unbundling; impact of new pipeline
supplies; and success of the Company's year 2000 readiness
efforts and those of its vendors and customers.

New Accounting Standards and Pronouncements

During fiscal year 1998, the Company implemented Statement of
Financial Accounting Standards (SFAS) No. 128, "Earnings per
Share," which establishes standards for computing and presenting
earnings per share, and SFAS No. 129, "Disclosure of Information
about Capital Structure," which establishes standards for
disclosure requirements regarding capital structure. Both SFAS
No. 128 and No. 129 have no material impact on the Company's
financial reporting.

The Financial Accounting Standards Board issued new accounting
standards which the Company will adopt in future periods.  SFAS
No. 130, "Reporting Comprehensive Income," establishes standards
for reporting and the disclosure of comprehensive income and its
components.  This standard is effective in fiscal year 1999 and
is not expected to have a material impact on the Company's
financial reporting.  SFAS No. 131, "Disclosures About Segments
of an Enterprise and Related Information," requires disclosure of
operating segments, including disclosures about products and
services, geographic areas and major customers.  It is effective
in fiscal year 1999 and is not expected to have a material impact
on the Company's financial reporting.  SFAS No.

<PAGE>

132, "Employer's Disclosures About Pensions and Other Postretirement
Benefits," revises employer's disclosures about pension and other
postretirement benefit plans.  It does not change the measurement
of recognition of those plans.  Effective in fiscal year 1999,
the standard is not expected to have a significant impact on the
Company's financial reporting.  SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," establishes
standards for recording all derivative instruments as assets and
liabilities measured at fair value.  The standard is effective in
the fourth quarter of fiscal year 1999 and is not expected to
have a material impact on the Company's financial position.

The American Institute of Certified Public Accountants issued
Statement of Position (SOP) 98-1, "Accounting for the Costs of
Computer Software Developed and Obtained for Internal Use," and
SOP 98-5, "Reporting on the Costs of Start-up Activities."  Both
are effective in fiscal year 2000 and adoption is not expected to
have a material impact on the Company's financial position.

Year 2000 Readiness

The Company has evaluated its principal computer systems and
noninformation technology systems including, but not limited to,
telecommunication systems, automated meter reading systems,
SCADA, regulator stations, plant remote control systems and
security systems to determine readiness for the year 2000.  These
systems are currently capable of processing the year 2000, or are
in the process of being upgraded or replaced by systems that are
similarly capable. All necessary program modifications and system
upgrades and testing are expected to be completed by the year
2000.  Costs incurred to date and costs expected to be incurred
to complete the year 2000 readiness are not material and will not
have a material impact on the Company's financial position or
results of operations.  The Company is currently assessing year
2000 issues with third parties with whom it has a material
relationship.  Except for the Company's major pipeline supplier,
who has provided assurance of compliance, the Company has not
determined the level of third-party risk.  Preparation of a
contingency plan to address failure of various systems is in
process and is expected to be finalized prior to September 30,
1999.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company does not enter into material market risk sensitive transactions.

<PAGE>

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

(a)  Financial Statements required by Regulation S-X

Consolidated Statements of Income                       EnergyNorth, Inc.

(In thousands, except per share amounts)
For the years ended September 30,             1998        1997       1996
-------------------------------------------------------------------------
Operating revenues                        $109,926    $105,871    $88,954
                                                                           
Operating expenses:                                                         
  Cost of sales                             64,124      61,829     44,941
  Operations and maintenance                23,073      21,658     21,660
  Depreciation and amortization              6,604       6,153      5,825
  Taxes other than income taxes              4,072       2,876      3,946
  Federal and state income taxes             3,102       3,808      3,635
                                          -------------------------------
      Total operating expenses             100,975      96,324     80,007
                                          -------------------------------

Operating income                             8,951       9,547      8,947
                                                                              
Other income                                 1,173         956        907
                                                                            
Interest expense:                                                             
  Interest on long-term debt                 3,897       2,917      3,004
  Other interest                               849       1,068        772
                                          -------------------------------
      Total interest expense                 4,746       3,985      3,776
                                          -------------------------------
                                                                             
Net income                                $  5,378    $  6,518    $ 6,078
                                          ===============================
                                                                            
Weighted average shares outstanding          3,273       3,243      3,216
                                          ===============================

Earnings per share                        $   1.64    $   2.01    $  1.89
                                          ===============================

<TABLE>
<C> <S>
The accompanying notes are an integral part of these consolidated financial statements.

</TABLE>


<PAGE>
<TABLE>
<CAPTION>

Consolidated Balance Sheets                                                                 EnergyNorth, Inc.

(In thousands)
September 30,                                                                           1998         1997
---------------------------------------------------------------------------------------------------------
<C>                                                                                 <S>          <S>
Assets
  Property:                                                                                                          
    Utility plant, at cost                                                          $158,595     $146,830
    Accumulated depreciation and amortization                                         51,313       47,815
                                                                                    ---------------------       
        Net utility plant                                                            107,282       99,015
    Net nonutility property, at cost                                                   7,771        7,430
                                                                                    ---------------------       
        Net property                                                                 115,053      106,445
                                                                                    ---------------------       
  Current assets:                                                                                                    
    Cash and temporary cash investments                                                1,231        1,998
    Note receivable                                                                        -          111
    Accounts receivable (net of allowances of $1,127 in 1998 and $1,357 in 1997)       9,727        3,430
    Unbilled revenues                                                                    516          602
    Materials and supplies                                                             2,086        1,756
    Supplemental gas supplies                                                          9,653        9,120
    Prepaid and deferred taxes                                                         1,804        1,305
    Recoverable FERC 636 transition costs                                                252        1,261
    Prepaid expenses and other                                                         2,252        2,258
                                                                                    ---------------------  
        Total current assets                                                          27,521       21,841
                                                                                    ---------------------  
  Deferred charges and other assets:                                                                                 
    Regulatory asset - income taxes                                                    2,401        2,401
    Recoverable environmental costs                                                    6,113        6,546
    Other deferred charges                                                             1,941        1,923
    Other assets                                                                       2,121          289
                                                                                    ---------------------
        Total deferred charges and other assets                                       12,576       11,159
                                                                                    ---------------------
Total assets                                                                        $155,150     $139,445
                                                                                    =====================
                                                                                                                       
Stockholders' equity and liabilities                                                                                   
  Capitalization (see accompanying statements)                                      $ 95,280     $ 92,964
                                                                                    ---------------------  
  Current liabilities:                                                                                               
    Notes payable to banks                                                             3,524          100
    Current portion of long-term debt                                                  2,061          932
    Current portion of capital lease obligations                                           -           46
    Inventory purchase obligation                                                      8,712        7,852
    Accounts payable                                                                  10,431        6,046
    Deferred gas costs                                                                 3,841        1,300
    Accrued interest                                                                     272          311
    Accrued and deferred taxes                                                           342          111
    Accrued FERC 636 transition costs                                                    252        1,261
    Accrued environmental remediation costs                                            2,345        1,546
    Customer deposits and other                                                        3,761        3,299
                                                                                    ---------------------
        Total current liabilities                                                     35,541       22,804
                                                                                    ---------------------  
                                                                                                                       
  Commitments and contingencies                                                                                      
  Deferred credits:                                                                                                  
    Deferred income taxes                                                             18,828       18,302
    Unamortized investment tax credits                                                 1,610        1,734
    Regulatory liability - income taxes                                                1,141        1,254
    Contributions in aid of construction and other                                     2,750        2,387
                                                                                    ---------------------
        Total deferred credits                                                        24,329       23,677
                                                                                    ---------------------  
Total stockholders' equity and liabilities                                          $155,150     $139,445
                                                                                    =====================

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

 </TABLE>

<PAGE>
<TABLE>
<CAPTION>


Consolidated Statements of Capitalization                           EnergyNorth, Inc.

(In thousands, except share information)
September 30,                                                           1998       1997
---------------------------------------------------------------------------------------
<C>                                                                  <S>        <S>                    
Capitalization:
  Common stockholders' equity:                                                                                       
    Common stock - par value of $1 per share; 10,000,000                                                           
      shares authorized; 3,317,498 and 3,243,543 shares                                                          
      issued and outstanding in 1998 and 1997, respectively          $ 3,317    $ 3,244
    Amount in excess of par                                           32,445     30,428
    Retained earnings                                                 15,128     14,050
                                                                     ------------------
        Total common stockholders' equity                             50,890     47,722
                                                                     ------------------
                                                                                                                       
  Long-term debt:                                                                                                    
    First Mortgage Bonds                                                                                           
      Due 2009                                            8.44%        3,667      4,000
      Due 2019                                            9.70%        7,000      7,000
      Due 2020                                            9.75%       10,000     10,000
      Due 2027                                            7.40%       21,975     22,000
                                                                                                                       
    Mortgage notes payable                                                                                         
      Due 1999                                            8.75%        1,300      1,400
      Due 2008                                            8.00%          899        959
                                                                                                                       
    Notes payable                                                                                                  
      Due 2000                                            prime          700          -
      Due through 2003                          prime plus .50%          631        815
      Due through 2003                             2.9% - 10.9%          279          -
                                                                     ------------------
                                                                      46,451     46,174
    Less current portion                                               2,061        932
                                                                     ------------------
        Total long-term debt                                          44,390     45,242
                                                                     ------------------
Total capitalization                                                 $95,280    $92,964
                                                                     ==================

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>

Consolidated Statements of Common Stockholders' Equity                               EnergyNorth, Inc.



                                                             Common stock                 
                                               --------------------------                 Total common
                                                   $1.00        Amount in    Retained    stockholders'
(In thousands, except per share amounts)       par value    excess of par    earnings           equity
------------------------------------------------------------------------------------------------------
<C>                                               <S>             <S>        <S>               <S>
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

Net income                                             -                -       6,518            6,518
Common stock - cash dividend ($1.25 per share)         -                -      (4,054)          (4,054)
Issuance of common stock under the Dividend
    Reinvestment and Stock Purchase Plan               2               29           -               31
Issuance of common stock under the Key Employee
    Performance and Equity Incentive Plan              3               57           -               60
                                               -------------------------------------------------------
Balance, September 30, 1997                        3,244           30,428      14,050           47,722

Net income                                             -                -       5,378            5,378
Common stock - cash dividend ($1.31 per share)         -                -      (4,300)          (4,300)
Issuance of common stock under the Key Employee
    Performance and Equity Incentive Plan              4               95           -               99
Issuance of common stock for acquisition              69            1,922           -            1,991
                                               -------------------------------------------------------  
Balance, September 30, 1998                       $3,317          $32,445     $15,128          $50,890
                                               =======================================================        

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>

Consolidated Statements of Cash Flows                                         EnergyNorth, Inc.
(In thousands)
For the years ended September 30,                                   1998        1997       1996
-----------------------------------------------------------------------------------------------
<C>                                                             <S>         <S>         <S>
Cash flows from operating activities:
  Net income                                                    $  5,378    $  6,518    $ 6,078
  Noncash items:                                                                                                           
    Depreciation and amortization                                  7,152       6,869      6,606
    Deferred taxes and investment tax credits, net                   345       1,521      1,081
  Changes in:                                                                                                              
    Accounts receivable, net                                       1,066      (1,401)       142
    Unbilled revenues                                                 86         (20)         4
    Inventories                                                     (472)       (247)      (931)
    Prepaid expenses and other                                        28        (211)       (79)
    Deferred gas costs                                             2,541       5,083     (9,428)
    Accounts payable                                                (728)       (143)     1,421
    Accrued liabilities                                              460         366       (171)
    Accrued/prepaid taxes                                           (400)     (1,233)     1,495
  Payments for environmental costs and other                      (1,242)     (3,104)      (823)
                                                                -------------------------------
      Net cash provided by operating activities                   14,214      13,998      5,395
                                                                ------------------------------- 
                                                                                                                             
Cash flows from investing activities:                                                                                        
  Additions to property                                          (14,716)    (13,262)    (8,783)
  Change in note receivable, net                                     131         (72)       (39)
  Other investing activities                                         249           -          -
                                                                ------------------------------- 
      Net cash used for investing activities                     (14,336)    (13,334)    (8,822)
                                                                -------------------------------           
                                                                                                                             
Cash flows from financing activities:                                                                             
  Issuance of common stock                                            99          91        802
  Cash dividends on common stock                                  (4,300)     (4,054)    (3,827)
  Issuance of long-term debt                                         646      22,616      1,827
  Repayment of long-term debt                                     (1,338)     (8,055)    (3,536)
  Repayment of capital lease obligations                             (46)       (229)      (256)
  Change in notes payable to banks                                 3,392      (9,435)     7,785
  Change in inventory purchase obligation                            860         (15)       738
  Change in other financing activities                                42        (355)        89
                                                                -------------------------------      
      Net cash (used for) provided by financing activities          (645)        564      3,622
                                                                                                                             
Net(decrease)increase in cash and temporary cash investments        (767)      1,228        195
Cash and temporary cash investments, beginning of year             1,998         770        575
                                                                ------------------------------- 
Cash and temporary cash investments, end of year                $  1,231    $  1,998    $   770
                                                                =============================== 

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

</TABLE>

<PAGE>

Note 1.  Accounting Policies

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

Principles of Consolidation

The accompanying consolidated 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, EnergyNorth
Natural Gas, Inc., located in southern and central New Hampshire.
The rates and accounting practices followed by the gas
distribution subsidiary are regulated by the State of New
Hampshire Public Utilities Commission (Commission). The Company's
accounting policies conform to generally accepted accounting
principles applicable to rate-regulated enterprises and reflect
the effects of the rate-making 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, EnergyNorth Propane, Inc., and provides service and
sells appliances through its utility subsidiary.

During fiscal year 1998, the Company acquired two mechanical
contracting operations and, through a nonregulated subsidiary,
ENI Mechanicals, Inc., provides design, construction and service
of plumbing, heating, ventilation, air conditioning and process
piping systems to commercial, industrial and institutional
customers (see Note 9).

Business Segments

The Company added a mechanical contracting segment to its
operations during fiscal year 1998. Segmented operating results
and other financial data are presented in the following table (in
thousands):

Fiscal Year                                                  1998
-----------------------------------------------------------------
Revenues:
    Energy segment                                      $  96,506
    Mechanical contracting segment                         13,426
Operating income:                                                              
    Energy segment                                         11,670
    Mechanical contracting segment                            231
Identifiable assets:                                                           
    Energy segment                                        145,470
    Mechanical contracting segment                          8,391

<PAGE>

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 each month.  The Company records unbilled
revenues related to gas delivered but not billed at the end of the
accounting period.

Mechanical contracting work is performed under cost-plus-fee
contracts, fixed-price contracts and time and material contracts.
The Company follows the percentage-of-completion method of
accounting for contracts that extend for periods in excess of one
year.  Revenues and related costs for time and material contracts
are recognized as the work is performed.

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.  The Company
may adjust the approved CGA rate upward or downward on a monthly
basis.  The monthly cumulative adjustments may not exceed 10% of
the approved unit cost of gas sold.  Any difference remaining
between the cost of gas incurred and amounts billed to customers
at the end of each summer or winter period is deferred for rate-
making and accounting purposes to the next corresponding summer
or winter 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.

Depreciation

The Company provides for 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, 1998, 1997 and
1996.  The depreciation rates for nonregulated property, plant
and equipment were 7.5%, 8% and 8.2% for the years ended
September 30, 1998, 1997 and 1996, 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 is 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, 1998, regulatory assets

<PAGE>

included $6.1 million for environmental investigation and remediation
costs and $2.4 million of unrecovered deferred state income taxes
(see Note 7).

The unamortized cost of issuing debt at September 30, 1998 is $2
million.  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.

Investment Tax Credits

Investment tax credits are 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.

If long-term debt outstanding at September 30, 1998 had been
refinanced using new issue debt rates of interest that on average
are lower than the outstanding rates, the present value of those
obligations would have increased from the amounts outstanding in
the September 30, 1998 accompanying consolidated balance sheet by
20%.

Derivative Instruments and Hedging Activities

The Company utilizes call and put option contracts and futures
contracts to manage market risk associated with a portion of
anticipated gas supply requirements.  The Company's policy
prohibits utilization of derivatives for trading purposes.

Gains or losses on derivatives associated with forecasted
transactions are recognized when such forecasted transactions
affect earnings.  If a derivative instrument is terminated early
because it is probable that a transaction or forecasted
transaction will not occur, any gain or loss as of such date is
immediately recognized in earnings.  If such derivative is
terminated early for other economic reasons, any gain or loss as
of the termination date is deferred and recorded when the
associated transaction or forecasted transaction affects
earnings.

Although options and futures traded on the NYMEX are included in
the table below, they are not financial instruments since
physical delivery of natural and propane gas may be made pursuant
to these contracts.  They are a major part of the commodity risk
management program.

<PAGE>

The following table summarizes the types of hedges used and the
related financial information as of September 30, 1998:

Notional Volumes           Hedges of            NYMEX Contracts
---------------------------------------------------------------
Futures - gallons          Purchases                        159
Calls - MMBtu              Purchases                        302
Puts - MMBtu               Sales                            302

$ Amount (In thousands)
---------------------------------------------------------------
Deferred losses, net                                       $(31)


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

Supplemental disclosures of cash flow information were as follows
  (in thousands):

                                                 1998      1997      1996
-------------------------------------------------------------------------
Cash paid during the year for:
  Interest (net of amount capitalized)         $4,269    $4,080    $3,642
  Income taxes                                  3,246     3,972       899

Noncash investing and financing activities:
  Acquisition investment (see Note 9)           1,991         -         -

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 and classified as cash and temporary cash
investments.

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 through the CGA.

<PAGE>

The bank credit agreement provides for a .375% commitment fee on
the credit line and interest at prime (8.25% at September 30,
1998) 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
$10.5 million through February 1999.

As of September 30, 1998 and 1997, the gas inventories under the
trust agreement and controlled by the Company totaled $8.7
million and $7.8 million, respectively, and are included in
inventories in the accompanying consolidated balance sheets.
Inventory purchase obligations under this financing agreement are
reflected as a current liability in the accompanying consolidated
balance sheets.

Note 4.  Notes Payable to Banks

As of September 30, 1998, the Company had $26.2 million available
under various unsecured bank lines of credit that are renewed
annually, $3.5 million of which was outstanding.  The weighted
average interest rate on borrowings outstanding on September 30,
1998 was 7.8%.  The lines bear interest at prime, prime plus 1%
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% of the
lines.

Note 5.  Long-Term Debt

Interest payments for the First Mortgage Bonds are due
semiannually.  The First Mortgage Bonds are collateralized by
first mortgage liens on substantially all real property and
operating plant facilities of the Company's gas utility
operations.

The aggregate amounts of principal due for all long-term debt for
each of the five years subsequent to September 30, 1998 are as
follows (in thousands):

                        Fiscal year                        Amount
-----------------------------------------------------------------
                        1999                               $2,061
                        2000                                1,416
                        2001                                  572
                        2002                                  487
                        2003                                  435

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.

<PAGE>

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
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

At September 30, 1998 and 1997, a SFAS No. 109 related regulatory
liability amounted to $892,000 and $960,000, respectively, for
the tax benefit of unamortized investment tax credits, and
$249,000 and $294,000, 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>

The tax effects of cumulative differences that gave rise to the deferred tax
liabilities and deferred tax assets for the years ended September 30, 1998 and
1997 were as follows (in thousands):
                                                    1998              1997
--------------------------------------------------------------------------
Deferred tax assets:                                                          
    Deferred gas costs                           $ 1,450           $   240
    Contributions in aid of construction             759               726
    Unamortized investment tax credits               545               590
    Allowance for doubtful accounts                  434               524
    Other                                          1,285             1,044
                                                 ------------------------- 
        Total deferred tax assets                  4,473             3,124
                                                 ------------------------- 
                                                                            
Deferred tax liabilities:                                                   
    Property-related                              18,035            16,873
    Environmental costs                            1,455             1,936
    Other                                          2,073             1,880
                                                 ------------------------- 
        Total deferred tax liabilities            21,563            20,689
                                                 ------------------------- 
Net deferred tax liability                       $17,090           $17,565
                                                 =========================      

Deferred income taxes were classified in the accompanying consolidated balance
sheets at September 30, 1998 and 1997 as follows (in thousands):

                                                    1998              1997
--------------------------------------------------------------------------
Current                                          $(1,738)          $  (737)
Long-term                                         18,828            18,302
                                                 ------------------------- 
        Total                                    $17,090           $17,565
                                                 =========================

The components of federal and state income taxes reflected in the accompanying
consolidated statements of income for the years ended September 30, 1998, 1997
and 1996 were as follows (in thousands):

                                     1998           1997             1996
-------------------------------------------------------------------------
Federal:                                                                    
    Current                        $2,939         $3,649           $  (32)
    Deferred                         (265)          (383)           3,165
    Investment tax credits           (124)          (136)            (140)
                                   --------------------------------------
        Total federal               2,550          3,130            2,993
                                   --------------------------------------
                                                                            
State:                                                                      
    Current                           601            756              (65)
    Deferred                          (49)           (78)             707
                                   --------------------------------------
        Total state                   552            678              642
                                   --------------------------------------
Total provision for income taxes   $3,102         $3,808           $3,635
                                   ======================================     

<PAGE>

The total federal and state income tax provision, as a percentage of income
before federal and state income taxes, was 36.6%, 36.9% and 37.4% for the years
ended September 30, 1998, 1997 and 1996, 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):

                                                          1998    1997    1996
------------------------------------------------------------------------------
Tax calculated at statutory rate                        $2,883  $3,511  $3,302
Increase (reduction) in effective tax resulting from:                       
    Amortization of investment tax credit                 (124)   (136)   (140)
    Adjustment due to change in tax rates                  (28)    (28)    (28)
    State taxes, net of federal tax benefit                364     447     424
    Other, net                                               7      14      77
                                                        ----------------------
Total provision for income taxes                        $3,102  $3,808  $3,635
                                                        ======================

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 nonqualified 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.

Net periodic pension cost included the following components (in thousands):

                                                    1998      1997      1996
----------------------------------------------------------------------------
Service cost for benefits earned                 $   684   $   663   $   624
Interest cost on projected benefit obligations     1,397     1,316     1,193
Actual return on plan assets                        (442)   (4,526)   (1,230)
Net amortization and deferral                     (1,143)    3,101      (103)
                                                 ---------------------------
Net periodic pension cost                        $   496   $   554   $   484
                                                 ===========================

<PAGE>

<TABLE>
<CAPTION>

The following table sets forth the funded status of the plans at September 30,
1998 and 1997 (in thousands):

                                                              1998                          1997
------------------------------------------------------------------------------------------------
                                                       Accumulated                   Accumulated
                                             Assets       benefits         Assets       benefits
                                             exceed         exceed         exceed         exceed
                                        accumulated         assets    accumulated         assets
                                           benefits     (unfunded)       benefits     (unfunded)
                                        --------------------------------------------------------
<C>                                         <S>            <S>            <S>
Vested benefit obligation                   $16,275        $ 1,442        $13,502        $ 1,112
                                        ========================================================
                                        
Accumulated benefit obligation              $16,820        $ 1,686        $14,015        $ 1,271
                                        ========================================================
                                                                                                                      
Projected benefit obligation                $20,119        $ 2,326        $16,965        $ 2,001
Plan assets at fair value                    21,316              -         21,018              -
                                        --------------------------------------------------------     
Funded status                                 1,197         (2,326)         4,053         (2,001)
Unrecognized transition                                                                                              
  (asset) obligation                           (357)           250           (440)           312
Unrecognized prior service cost                 447              6            535              6
Unrecognized net loss (gain)                    649            713         (2,588)           540
Additional minimum liability                      -           (329)             -           (128)
Adjustment for contribution                                                                               
   8/1/98 - 9/30/98                              78              -              -              -
                                        --------------------------------------------------------     
Prepaid pension (pension liability)         $ 2,014        $(1,686)       $ 1,560        $(1,271)
                                        ========================================================     
</TABLE>


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

<TABLE>
<CAPTION>

                                                    1998         1997       1996
-------------------------------------------------------------------------------------
<C>                                             <S>          <S>          <S>
Discount rate                                       7.0%         7.5%        7.5%
Rate of increase in future compensation levels  4.0% - 5.5%  4.0% - 5.5%  4.0% - 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 $254,000,
$242,000 and $216,000 for the years ended September 30, 1998, 1997 and 1996,
respectively.

The Company is a participating employer in a defined contribution profit sharing
plan and trust covering certain employees who meet specific age and service
requirements.  No profit sharing contributions were made to the plan in 1998.
The plan includes a salary reduction provision with a matching discretionary
employer contribution.  The Company contributed $33,000 in 1998.

The Company is also a contributing employer to various area-wide, union-
negotiated, multi-employer defined pension plans covering certain employees by
craft.  Contributions totaled $245,000 in 1998.

<PAGE>

Other Postemployment Benefits

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

The expense recorded in fiscal 1998, 1997 and 1996 for providing postretirement
benefits, including amortization of the accumulated projected benefit obligation
over a 20-year period, was $486,000, $542,000 and $588,000, 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.

The following table sets forth the funded status of the plans at September 30,
1998 and 1997 (in thousands):
                                                                 1998      1997
-------------------------------------------------------------------------------
Accumulated postretirement benefit obligation as of July 31:                    
    Retirees                                                  $ 2,289   $ 2,477
    Fully eligible active plan participants                     1,347     1,130
    Other active participants                                   1,643     1,606
                                                              -----------------
                                                                5,279     5,213
Plan assets at fair market value                               (3,013)   (2,555)
Unrecognized transition obligation                             (3,922)   (4,183)
Unrecognized net gain                                           1,826     1,697
                                                              -----------------
Accrued postretirement benefit cost at July 31                    170       172
Contributions for the two-month period ended September 30         118       133
                                                              -----------------
Accrued postretirement benefit cost at September 30           $    52    $   39
                                                              =================

The components of net periodic postretirement benefit cost at September 30, 1998
and 1997 were as follows (in thousands):
                                                                   1998    1997
-------------------------------------------------------------------------------
Service cost - benefits attributed to services during the year    $ 122   $ 133
Interest cost on accumulated postretirement benefit obligation      385     367
Actual asset return                                                (180)   (462)
Net amortization and deferral                                       159     504
                                                                  -------------
Net periodic postretirement benefit cost                          $ 486   $ 542
                                                                  =============

A 9% average annual rate of increase in the per capita costs of covered health
care benefits was assumed for fiscal 1998, 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 $212,000 increase in the
accumulated postretirement benefit obligation as of July 31, 1998 and an
increase in the aggregate of the service cost and interest cost components of
net periodic postretirement benefit cost of $21,000 for fiscal 1998.  A discount
rate of 7% was used to determine the accumulated postretirement

<PAGE>

benefit obligation.  The expected long-term rate of return on plan assets is
9%. Plan assets are invested in common stocks and bonds.

Note 9.  Acquisition

In May 1998, the Company acquired Northern Peabody, Inc. (NPI) and Granite State
Plumbing and Heating, Inc. (GSPH).  Both NPI and GSPH are mechanical contractors
engaged in the design, construction and service of plumbing, heating,
ventilation, air conditioning and process piping systems in northern New
England.  They became wholly owned subsidiaries of ENI Mechanicals, Inc., a
subsidiary of the Company.  For financial statement purposes, the acquisition
was recorded as a purchase.  Accordingly, the results of operations of NPI and
GSPH are included in the accompanying consolidated financial statements since
May 1, 1998.  The assets of the acquired companies had a combined fair value of
approximately $8.5 million at the date of acquisition.  The Companies were
acquired for an aggregate purchase price of approximately $2 million, which was
comprised of 69,890 shares of the Company's common stock.  NPI and GSPH
outstanding debt and liabilities at the date of the acquisition were
approximately $6.5 million.  The purchase price was allocated to assets, net of
liabilities, based on estimated fair values at the date of acquisition.  The
fair value of assets purchased was written down by $245,000 to adjust for
goodwill.

The following unaudited pro forma summary combines the consolidated results of
operations of the Company and NPI and GSPH as if the acquisition had occurred at
the beginning of fiscal years 1998, 1997 and 1996.  The pro forma summary is
presented for information purposes only and is not necessarily indicative of
what would have occurred if the acquisition had been made as of those dates.  In
addition, the pro forma summary is not intended to be a projection of future
results.

Pro forma information (unaudited)                                              
(In thousands, except share information)                                    
                                                                                
For the years ended September 30,            1998        1997        1996
-------------------------------------------------------------------------
Operating revenues                       $127,841    $137,071    $117,810
Net income                                  5,584       6,809       6,411
Earnings per share                           1.68        2.06        1.95

<PAGE>

Note 10.  Operating Leases

The Company leases certain facilities and equipment under long-term,
noncancelable operating lease agreements having terms greater than one year.
Future minimum rental commitments for these leases, at September 30, 1998, are
approximated as follows (in thousands):

                        Fiscal year                        Amount
-----------------------------------------------------------------
                        1999                                 $350
                        2000                                  322
                        2001                                  257
                        2002                                  223
                        2003                                   95

The total rental expense charged to operations for the years ended September 30,
1998, 1997 and 1996 was approximately $557,000, $574,000 and $616,000,
respectively.

Note 11. 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 1999 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 several facilities
for the manufacture of gas from coal, a process used through the mid-1900s 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.  Like
other companies in the natural gas industry, the Company is a party to
governmental actions associated with former gas manufacturing sites.

The Company is engaged in remedial action at a former gas manufacturing site in
Concord, New Hampshire, and is participating with Public Service Company of New
Hampshire in ongoing site assessment and evaluation of remedial options at a
site located in Laconia, New Hampshire.  The Company received a notice of
potential responsibility from the Environmental Protection Agency related to a
site in the area of its former gas manufacturing plant in Nashua, New Hampshire,
and also received a request from the New Hampshire Department of Environmental
Services to investigate this former gas manufacturing site.  Costs to complete
remedial action at the Concord site and the

<PAGE>

Company's share of investigation and evaluation costs at the other sites are
estimated to range from $2.3 million to $5 million.  Along with costs incurred
to date, the Company has recorded $2.3 million in accrued liability at
September 30, 1998 with a corresponding charge to recoverable environmental
costs.  Actual environmental remediation costs to be incurred depend on a number
of factors, and therefore future costs may differ from the amount currently
recorded as a liability. Factors that may bear on cost include changes
in remediation techniques or practices, changes in regulatory standards
and the nature and extent of contamination at the sites.  The Company accrues
environmental investigation and cleanup costs with respect to former gas
manufacturing sites and other environmental matters when it is probable that a
liability exists and the amount or range of amounts can be reasonably estimated.

The Company has received orders from the Commission that provide for recovery
from customers, over a seven-year period, of substantially all costs, excluding
carrying costs, of past and future investigation, remediation and recovery
efforts for the Concord site.  The unamortized balance of unrecovered costs
($5.5 million at September 30, 1998) is excluded from rate base.  The Company
may not earn a return or charge rates to customers based on amounts not included
in rate base.

The Company has instituted several lawsuits to recover the costs of
investigation and remediation of the Concord site and investigation of the
Laconia site.  Through November 1998, the Company reached settlements with
certain of the defendants in those suits in an aggregate amount of $3.5 million.
The settlements also include further payment to the Company of a portion of
future Concord site remediation costs.  The proceeds are being reflected as
reductions in deferred charges, as shown in the accompanying consolidated
balance sheets.  The Company expects that such settlement amounts will reduce
the amount that it will be permitted by the Commission to recover from its
customers.

The Company is pursuing and intends to 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 will continue 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>

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, 1998 and 1997, 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, 1998. 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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
September 30, 1998, 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.






ARTHUR ANDERSEN LLP
Boston, Massachusetts
November 4, 1998

<PAGE>

     (b)  Supplementary Financial Information

<TABLE>
<CAPTION>

Selected Quarterly Financial Data (Unaudited)                                             EnergyNorth, Inc.

(In thousands, except per    Operating        Operating    Net income     Earnings (loss)     Cash dividend
 share amounts)               revenues    income (loss)        (loss)           per share    paid per share
-----------------------------------------------------------------------------------------------------------
<C>                            <S>              <S>           <S>                   <S>                <S>          
First Quarter
1998                           $30,892          $ 4,801       $ 4,142               $1.28              $.32
1997                            29,454            4,434         3,618                1.12               .305
-----------------------------------------------------------------------------------------------------------
Second Quarter
1998                            42,032            6,658         5,836                1.80               .32
1997                            48,898            7,295         6,581                2.03               .305
-----------------------------------------------------------------------------------------------------------
Third Quarter
1998                            20,498             (823)       (1,758)               (.54)              .335
1997                            18,085             (853)       (1,576)               (.49)              .32
-----------------------------------------------------------------------------------------------------------
Fourth Quarter
1998                            16,504           (1,685)       (2,842)               (.86)              .335
1997                             9,434           (1,329)       (2,105)               (.65)              .32
-----------------------------------------------------------------------------------------------------------
</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, 1998.


                            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 Registrant's Proxy Statement for its Annual Meeting to be held
February 3, 1999, except for information relating to identification of Executive
Officers of the Registrant which is contained in Part I of this Report.


ITEM 11.  EXECUTIVE COMPENSATION

The information called for by this Item is incorporated by reference to
"Compensation of Directors," "Executive Compensation" and "Noncontributory
Retirement Plan" on pages 5 through 7 of the Registrant's Proxy Statement for
its Annual Meeting to be held February 3, 1999.

<PAGE>

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 3, 1999.
     

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

There are no relationships or related transactions that require disclosure.
     
                            PART IV

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

<TABLE>
<CAPTION>

(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
         <C>                                                                    <S>
         Consolidated Statements of Income for the years ended
           September 30, 1998, 1997 and 1996                                      22
         Consolidated Balance Sheets at September 30, 1998 and 1997               23
         Consolidated Statements of Capitalization at September 30,
           1998 and 1997                                                          24
         Consolidated Statements of Common Stockholders' Equity for the years
           ended September 30, 1998, 1997 and 1996                                25
         Consolidated Statements of Cash Flows for the years ended
           September 30, 1998, 1997 and 1996                                      26
         Notes to Consolidated Financial Statements                             27-39
         Report of Independent Public Accountants                                 40

</TABLE>

<PAGE>

<TABLE>
<CAPTION>

    (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:
         
        <C>      <S>                                                          <S>                           
        Schedule                                                              Page No. in
        Number               Description                                      this Report

        II       Consolidated Valuation and Qualifying Accounts for the
                 three years ended September 30, 1998                             44

        Report of Independent Public Accountants                                  40

        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 46 through 48.

(b)  Reports on Form 8-K

         There were no reports on Form 8-K filed during the quarter ended September 30, 1998.

(c)  Exhibits - See Exhibit Index on pages 46 through 48

(d)  Financial Statement Schedules

</TABLE>

<PAGE>

<TABLE>
<CAPTION>
                                                                     SCHEDULE II
                                
                                
                                
                        ENERGYNORTH, INC.
         CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
                         (In thousands)
  
Reserves that are deducted in the balance sheets
from assets to which they apply:
  
                                                    Additions
                                              ----------------------
                                  Balance at  Charged to  Charged to                   Balance
   Year ended                      beginning   costs and       other                    at end
September 30,   Description        of period    expenses    accounts(1)  Deductions  of period
----------------------------------------------------------------------------------------------
         <C>    <S>                   <S>         <S>           <S>          <S>        <S>           
         1998   Allowance for                                                                      
                  doubtful accounts   $1,357      $1,095        $125         $1,450     $1,127
         1997   Allowance for                                                                      
                  doubtful accounts    1,211       1,232         140          1,226      1,357
         1996   Allowance for                                                                      
                  doubtful accounts      950       1,137         143          1,019      1,211
  
______________________
(1) Represents recoveries on accounts previously written off

</TABLE>

<PAGE>

                           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 22, 1998         by: /s/ Robert R. Giordano
                                    Robert R. Giordano
                                    President and 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 22, 1998.

/s/ Robert R. Giordano                   Director, President and
Robert R. Giordano                       Chief Executive Officer
                                         (principal executive officer)
                                                          
/s/ Frank L. Childs                      Senior Vice President, Treasurer and
Frank L. Childs                          Chief Financial Officer
                                         (principal financial officer)
                                                          
/s/ David A. Skrzysowski                 Vice President and Controller
David A. Skrzysowski                     (principal accounting officer)
                                                          
/s/ Edward T. Borer                      Director
Edward T. Borer                                           
                                                          
/s/ N. George Mattaini                   Director
N. George Mattaini                                        
                                                          
/s/ John E. Tulley II                    Director
John E. Tulley II                                         
                                                          
/s/ Richard B. Couser                    Director
Richard B. Couser                                         
                                                          
/s/ Sylvio L. Dupuis                     Director
Sylvio L. Dupuis                                          

<PAGE>

                           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 3.1 to
                    EnergyNorth, Inc.'s Quarterly Report on Form 10-Q (File
                    No. 1-11441) for the quarter ended March 31, 1996.

           3.2      By-Laws of EnergyNorth, Inc., as amended, 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 to 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 to
                    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 to
                    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,
                    is incorporated by reference to Exhibit 4.4 to
                    EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for the
                    fiscal year ended September 30, 1996.

            4.5     Sixth Supplemental Indenture, dated as of
                    September 15, 1997, to Gas Service, Inc. General and
                    Refunding Mortgage Indenture, dated as of June 30, 1987,
                    is incorporated by reference to Exhibit 4.5 to
                    EnergyNorth Natural Gas, Inc.'s Amendment No. 1 to
                    Registration Statement on Form S-1, No. 333-32949, dated
                    September 10, 1997.

           4.6      Copies of credit agreements defining the rights
                    of holders of long-term debt of certain subsidiaries of
                    EnergyNorth, Inc., under which the amounts of the debt
                    issued do not

<PAGE>

                    exceed 10% of the consolidated assets of
                    EnergyNorth, Inc., will be furnished to the Securities
                    and Exchange Commission upon request.

           4.7      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.

          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 to
                    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, is incorporated by
                    reference to Exhibit 10.3 to EnergyNorth, Inc.'s Form
                    10-K (File No. 1-11441) for the fiscal year ended
                    September 30, 1996.

          10.4      Deferred Compensation Agreement, dated as of
                    October 1, 1997, between Robert R. Giordano and the
                    Registrant is incorporated by reference to Exhibit
                    10.4 to EnergyNorth, Inc.'s Form 10-K (File No.
                    1-11441) for fiscal year ended September 30, 1997.

          10.5      Deferred Compensation Agreement, dated as of
                    October 1, 1997, between Richard P. Demers and the
                    Registrant is incorporated by reference to Exhibit
                    10.7 to EnergyNorth, Inc.'s Form 10-K (File No.
                    1-11441) for fiscal year ended September 30, 1997.

          10.6      Deferred Compensation Agreement, dated as of
                    October 1, 1997, between Frank L. Childs and the
                    Registrant is incorporated by reference to Exhibit
                    10.8 to EnergyNorth, Inc.'s Form 10-K (File No.
                    1-11441) for fiscal year ended September 30, 1997.

          10.7      Deferred Compensation Agreement, dated as of
                    October 1, 1997, between Michelle L. Chicoine and the
                    Registrant is incorporated by reference to Exhibit
                    10.9 to EnergyNorth, Inc.'s Form 10-K (File No.
                    1-11441) for fiscal year ended September 30, 1997.

          10.8      EnergyNorth, Inc. 1992 Directors' Deferred
                    Compensation Plan, as amended is incorporated by
                    reference to Exhibit 10.10 to EnergyNorth, Inc.'s
                    Form 10-K (File No. 1-11441) for fiscal year ended
                    September 30, 1997.

          10.9      Employment Agreement, dated as of December 1, 1998,
                    between Robert R. Giordano and the Registrant.

<PAGE>

          10.10     Employment Agreement, dated as of December 1, 1998,
                    between Michelle L. Chicoine and the Registrant.

          10.11     Management Continuity Agreement, dated as of
                    November 20, 1998, between Robert R. Giordano and the
                    Registrant.

          10.12     Management Continuity Agreement, dated as
                    of November 20, 1998, between Kenneth M. Margossian
                    and the Registrant.

          10.13     Management Continuity Agreement, dated as
                    of December 2, 1996, between Michelle L. Chicoine and
                    the Registrant is incorporated by reference to Exhibit
                    10.18 to EnergyNorth, Inc.'s Form 10-K (File No. 1-
                    11441) for the fiscal year ended September 30, 1996.

          10.14     Management Continuity Agreement, dated as
                    of December 2, 1996, between Frank L. Childs and the
                    Registrant is incorporated by reference to Exhibit 10.19
                    to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for
                    the fiscal year ended September 30, 1996.

          10.15     Management Continuity Agreement, dated as
                    of December 7, 1995, between Richard P. Demers and the
                    Registrant is incorporated by reference to Exhibit 10.20
                    to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for
                    the fiscal year ended September 30, 1996.

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

          10.17     EnergyNorth, Inc. Directors' Incentive
                    Compensation Plan is incorporated by reference to
                    Exhibit 10 to EnergyNorth Inc.'s Quarterly Report on
                    Form 10-Q (File No. 1-11441) for the quarter ended March
                    31, 1997.

          10.18     EnergyNorth, Inc. 1998 Stock Option Plan.

          21        Subsidiaries of the Registrant.

          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.