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, 1999
                    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.)

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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.  [   ]

At October 8, 1999, nonaffiliates held 3,206,137 shares of the registrant's $1.00 par value common
stock.  On December 2, 1999, the aggregate market value of those shares was $175,536,001.

At the close of business on December 2, 1999, the registrant had 3,322,903 outstanding shares of its
$1.00 par value common stock.

                            DOCUMENTS INCORPORATED BY REFERENCE

Incorporated  Document                                              Location in Form 10-K
----------------------                                              ---------------------
        NONE

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                                    Page 1 of 60 pages.
                           Exhibit Index appears on Pages 56 through 59.



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                        TABLE OF CONTENTS
<C>     <S>                                                                <S>
Part I                                                                     Page No(s).
                                                                         --------------

Item 1. Business
         General                                                               4-6
         Utility Gas Distribution Business                                      6
         Retail Propane Business                                               6-7
         Mechanical Contracting Business                                        7
         Summary of Revenues                                                   7-8
         Deregulation                                                           8
         Competition                                                           8-9
         Gas Supply
           General                                                              9
           Supply, Pipeline Transportation and Underground Storage Contracts   9-10
           Cost of Purchased and Produced Gas                                   10
         Supervision and Regulation                                           10-11
         Employees                                                              11
Item 2.  Properties                                                             11
Item 3.  Legal Proceedings                                                    11-13
Item 4.  Submission of Matters to a Vote of Security Holders                    13

Part II

Item 5.  Market for Registrant's Common Equity and Related
         Stockholder Matters                                                    14
Item 6.  Selected Financial Data                                                14
Item 7.  Management's Discussion and Analysis of Financial Condition
         and Results of Operations                                            15-20
Item 7A. Quantitative and Qualitative Disclosures about Market Risk             20
Item 8.  Financial Statements and Supplementary Data                          21-43
Item 9.  Changes in and Disagreements with Accountants on Accounting
         and Financial Disclosure                                               43

Part III

Item 10.  Directors and Executive Officers of the Registrant                  44-45
Item 11.  Executive Compensation                                              46-51
Item 12.  Security Ownership of Certain Beneficial Owners and Management        51
Item 13.  Certain Relationships and Related Transactions                        52

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

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K       52-54
         Signatures                                                               55
         Exhibit Index                                                          56-59
         Exhibit 23 - Consent of Independent Public Accountants                   60

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                        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.

On July 14, 1999, the Company and Eastern Enterprises (Eastern),
a Massachusetts business trust, entered into an Agreement and
Plan of Reorganization (Agreement) which provides for the merger
of the Company with a subsidiary of Eastern, as a result of which
the Company's subsidiaries would become wholly owned subsidiaries
of Eastern.  On November 4, 1999, Eastern entered into an
agreement to merge with KeySpan Corporation and, as a result, the
Company and Eastern amended the Agreement.  Under the amended
Agreement, holders of outstanding shares of the Company's common
stock will be paid entirely in cash and the closing will take
place simultaneously with the Eastern merger with KeySpan
Corporation.  If the Eastern/KeySpan Corporation merger is not
completed, the Company and Eastern would nonetheless merge, and
holders of outstanding shares of the Company's common stock can
elect to receive cash, Eastern common stock or a combination of
cash and stock as set forth in the Agreement.  Completion of the
merger is subject to approval by the Company's stockholders and
receipt of satisfactory regulatory approvals, including approval
by the State of New Hampshire Public Utilities Commission
(Commission) and the Securities and Exchange Commission.

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 LPG)
and serves customers in central and southern New Hampshire. ENPI
is a member of VGS Propane, LLC (VGSP), a joint venture with
Northern New England Gas Corporation.  VGSP is a Vermont limited
liability company which provides LPG 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.



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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
482,000 in 28 communities situated mostly in southern and central
New Hampshire, which includes the communities of Nashua,
Manchester, Concord and Laconia.  In 1999, ENGI was awarded the
franchise for the city of Berlin, New Hampshire.  Berlin is
situated in the northern part of New Hampshire approximately 100
miles from the rest of the service area.  The remaining service
area encompasses approximately 922 square miles and is located
within 30 to 85 miles of greater Boston.  ENGI's service
territory offers a favorable business climate with no general
sales or personal income taxes, a productive labor force and a
comfortable, safe and clean environment for residents and
tourists.

The New Hampshire nonfarm employment growth rate was 2.1% in
1999.  This compares to a 2.0% average growth rate nationally and
a 1.6% average rate for New England for the same period. New
Hampshire employment growth in 2000 is forecasted to be 1.7%. New
housing permits increased 16.6% in 1999 compared to 1998, and are
expected to decrease by 5.2% in 2000.  The New Hampshire
unemployment rate for 2000 is forecasted at 2.7% compared to 2.5%
in 1999, and the labor force is forecasted to increase by 1.7% in
2000.  Job growth and low unemployment in the Company's service
area tend to result in an increase in gas volumes transported and
sold and numbers of customers.  (All employment and housing
statistics are taken from The New England Economic Project's
October 1999 Economic Outlook for New Hampshire.)  In fiscal
1999, the Company experienced net growth of 2.9% in natural gas
and transportation customers and 8.3% in propane customers over
1998.

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.  In 1999, ENGI expanded into Berlin, New Hampshire and
began providing natural gas service in early fiscal year 2000.
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 four years, ENGI has
experienced an annual average customer growth rate of 2.7%. This
compares to an approximate 1.1% 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



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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 Commission.  No operations are
outside New Hampshire.  While ENGI's franchise area is primarily
residential in character, 51% of sales volumes are commercial and
industrial.  As of September 30, 1999, the Company's utility
business served nearly 72,000 customers, of which approximately
88% were residential and 12% were commercial and industrial.
During fiscal 1999, no ENGI customer purchased more than 2.5% of
the total ENGI annual sales and transportation volume.

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, 1999, ENGI had 89 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, seven take stations located in
Manchester, Londonderry, Windham, Concord, Hooksett, Suncook and
Berlin 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 September 7, 1999, the Commission approved a petition filed by
ENGI 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.  At the request of
the State of New Hampshire Department of Corrections, ENGI is
providing natural gas service to a new prison complex being
constructed in Berlin.  The prison is 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 15,300 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



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propane requirement is purchased in the spot market. ENPI utilizes
fixed price contracts with certain suppliers to cover its retail
fixed price program, as well as to reduce price volatility during
the winter months. 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.  VGSP is the
largest Vermont-based propane company and services more than 10,000
customers throughout the state of Vermont.

On August 26, 1999, ENPI exercised its option under the VGSP
Operating Agreement to offer to sell its share of VGSP to
Northern New England Gas Corporation, the 51% member of VGSP.  In
accordance with the terms of the Operating Agreement, an
appraisal is underway to determine the fair value of each
member's ownership interest.  ENPI anticipates its withdrawal as
a member of VGSP will be completed in early 2000.

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, 1999 was $18.5 million compared to $16.2 million
last year, and approximately $13 million of the 1999 backlog is
expected to be completed in fiscal year 2000.

Summary of Revenues

Revenues attributable to various categories of gas distribution
and related operations during the last three fiscal years and
mechanical contracting operations for the fiscal year ended
September 30, 1999 and for the five-month period ended September
30, 1998 are as follows (in thousands, unaudited):


                                              September 30,
                                       --------------------------------
                                           1999        1998        1997
                                       --------------------------------
Utility (natural gas) sales service    $ 72,891    $ 82,686    $ 91,670
Utility transportation service            3,726       2,610       1,308
Propane gas sales                        11,164      11,204      12,893
Service and appliance sales               2,275       2,128       2,185
Rentals                                     854         899         937
Mechanical contract sales                31,391      13,426           -
                                       --------------------------------
                                       $122,301    $112,953    $108,993
                                       ================================


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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
83% of ENGI's and ENPI's customers use natural gas and propane
for heating.

Deregulation

ENGI has been providing gas transportation service, including
standby and balancing services for commercial and industrial
customers since late 1993.  Gas transportation service allows
customers to utilize ENGI's distribution system for the
transportation of gas purchased from third-party suppliers,
creating competition from gas marketers for the sale of gas to
end users.  At September 30, 1999, ENGI had 89 firm
transportation customers.  These customers are, for the most
part, large commercial and industrial customers.  The volume
transported for firm transportation customers in fiscal 1999 was
2.0 Bcf, 26% of the Company's total commercial and industrial
load and 15.8% 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 customers.  A full report
of recommendations by the participants, along with model terms
and conditions, is expected to be filed with the Commission in
late 1999.  ENGI cannot predict the outcome of the proceeding, or
the impact on transportation volumes or customers.

ENGI is the sole distributor and transporter of natural gas in
its franchise area.  The Tennessee Gas Pipeline Company
(Tennessee) serves all of ENGI's franchise area, except the city
of Berlin, which is served by the Portland Natural Gas
Transmission System.  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, some of whom 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



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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.  Most
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, Pipeline Transportation and Underground Storage
Contracts.  ENGI's gas supply is principally natural gas,
transported on interstate pipelines.  The primary pipeline ENGI
uses to bring natural  gas  to its distribution territory is the
Tennessee Gas Pipeline (TGP).  ENGI contracts for 56,833
Dekatherms (Dth) of primary firm and 8,000 Dth of interruptible
capacity on TGP.  ENGI also has a long-term contract with a New
England supplier for additional firm city gate delivery of 8,000
Dth per day (151 day service).

ENGI's natural gas supply contracts are a mix of long and short-
term agreements.  ENGI's firm supply contracts for fiscal year
1999, with terms of one to seven years, totaled 40,529 Dth per
day.  During fiscal year 1999, approximately 4.7% of ENGI's
natural gas supply portfolio was firm delivered winter
supplemental supply.  One percent of ENGI's annual supply in
fiscal year 1999 was purchased in the spot market.

In fiscal year 1999, approximately 61% of the gas delivered by
ENGI came from domestic pipeline sources, 24% from Canadian
pipeline sources, and 14% from supplemental pipeline sources.
LPG and liquefied natural gas (LNG) purchases from both domestic
and foreign sources made up approximately 1% of the gas delivered
by ENGI.  LPG and LNG are vaporized at ENGI's peakshaving
(production) plants as needed to supplement pipeline natural gas
supplies.  Unbundled end-user customers that are supplied by
third-party marketers accounted for nearly 15.8% of total load on
ENGI's system during fiscal year 1999.

All pipeline volumes to ENGI's city gates are transported via the
TGP, except for volumes which are transported to the city gate at
Berlin, New Hampshire by the Portland Natural Gas Transmission
System.  Canadian supplies are also transported by the suppliers
on the TransCanada Pipeline to the U.S. border, where ENGI takes
possession in this country and transports these supplies on the
Iroquois Gas Transmission System, the Portland Natural Gas
Transmission System and the TGP.  All domestic pipelines operate
under FERC approved tariffs.




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ENGI has underground storage agreements with four storage field
operators in the Pennsylvania-New York area.  ENGI fills these
storage fields each summer for use during the following winter.
Total combined storage controlled by ENGI equals 2,579,431 Dth
with daily withdrawal rights of 30,833 Dth.  All underground
storage fields operate under FERC approved tariffs.  ENGI also
owns on-site storage facilities capable of holding 115,660 Dth of
LPG and 13,057 Dth of LNG.  ENGI has contracted for 450,000 Dth
of supplemental pipeline supply, 100,000 Dth of LNG and 1,000,000
gallons of LPG for the upcoming winter (1999/2000).

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

Cost of Purchased and Produced Gas.  The average unit cost of gas
purchased and produced during the twelve months ended September
30, 1999 was approximately $3.78 per Mcf compared to $4.09 per
Mcf for the same period last year.  The 1999 average unit cost
reflects the lower cost of gas supply in the marketplace.  The
cost of gas rate authorized by the Commission permits recovery by
ENGI from its customers (or requires refunds to its customers) of
gas costs (including pipeline, storage, LPG and LNG) that are
higher (or lower) than the cost of gas included in base rates.
ENGI may adjust the approved cost of gas 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 cost of gas charges are reconciled twice
annually against actual costs, for summer and winter periods, and
future cost of gas rates are adjusted accordingly.

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 1999/2000 winter period.  The call options
provide the right, but not the obligation, to purchase gas at a
predetermined price by a certain date.  The purchase of call
options and the sale of put options create 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 are passed on to customers through the
cost of gas charge.

Margins earned on interruptible service, 280 day service and
capacity releases are passed on to firm customers through the
cost of gas charge.  In addition, costs associated with the fuel
inventory trust, including administrative fees and carrying
costs, are recovered through the cost of gas charge.

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.




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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, 1999, the Company had 459 full-time employees,
of whom 135 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 134 employees under a contract
that expires in 2000.

ITEM 2.  PROPERTIES

The Company's utility gas distribution facilities constitute the
majority of its physical assets.  As of September 30, 1999, ENGI
had approximately 1,113 miles of mains and 702 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 and vehicles.

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



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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, own or owned
several facilities at which manufactured gas plants (MGP)
operated.  MGPs were used to manufacture gas prior to the
introduction of natural gas to the Company's service area.
Generally, MGPs operated from the late 1800s to the early 1950s.
The MGPs produced wastes and by-products that may be considered
contaminated or hazardous under current law, and some of which
may still be present at such facilities.  Relevant environmental
laws can be used by the state and federal government  to hold the
Company strictly liable for the costs of studying and remedying
discarded by-products from MGPs owned and operated by its
predecessors.  The Company accrues environmental investigation
and cleanup costs with respect to former MGPs 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 the Company to undertake remedial investigation
and/or remedial action at MGPs located in Concord, Laconia,
Nashua, and Dover, New Hampshire.  At each MGP, the Company is
responding to the NHDES's requirements as described below.

In September 1992, the NHDES required the Company to undertake a
remedial investigation of the former MGP in Concord, New
Hampshire.  Study and remediation associated with the Concord MGP
is ongoing.  The estimated cost to complete this remedial action
ranges from $690,000 to $1.6 million, and the Company has
recorded $690,000 at September 30, 1999 in deferred charges.  The
Company received an order from the Commission approving recovery
from customers, over a seven-year period, of substantially all
costs, excluding carrying costs, incurred for the Concord MGP.
The total unamortized balance for the Concord site, including the
gas holder site, was $4.4 million as of September 30, 1999.

At the direction of the NHDES, the Company and Public Service
Company of New Hampshire (PSNH), an electric utility company,
conducted a remedial investigation of a former MGP in Laconia,
New Hampshire, and in January 1999 prepared a Remedial Action
Plan for that site.  Without admitting any liability, on
September 3, 1999, the Company entered into a Site
Responsibilities and Indemnity Agreement (SRIA) with PSNH.
Pursuant to the SRIA, the Company will pay $4.2 million to PSNH
over a twenty-four (24) month period.  In exchange, PSNH will
assume responsibility for all future site study and remediation,
and PSNH will indemnify the Company against such costs.  The
Company's legal liability under state and federal laws is
unaffected by the SRIA.  Through September 30, 1999, the Company
has paid $1 million under the SRIA.  The estimated costs
associated with work undertaken prior to the SRIA ranges from
$117,000 to $517,000, and the Company has recorded $3.3 million
in deferred charges at September 30, 1999.

During 1998, the Company and PSNH received Notice of Potential
Responsibility from the Environmental Protection Agency (EPA) for
the so-called Nashua River Asbestos Site.  The EPA contends that
wastes released from the former MGP in Nashua, New Hampshire are
commingled with asbestos wastes from a former Johns Manville
facility located adjacent to the former MGP.



<PAGE>




The Company's share of costs to complete the disposal of
contaminants that are the subject of EPA claims are estimated
to range from $375,000 to $450,000.  The Company and PSNH
subsequently received a notice from the NHDES requiring the
investigation of the former MGP site in Nashua.  The Company
estimates the cost of site investigation and characterization at
the Nashua MGP to range from $250,000 to $325,000.  The Company
recorded $625,000 in deferred charges at September 30, 1999.

In April 1999, the Company received notice from the NHDES to
investigate the former MGP site in Dover, New Hampshire.  PSNH
and another utility company, Northern Utilities, received similar
notices concerning the Dover MGP from the NHDES.  The Company
estimates its cost of that investigation and characterization to
range from $200,000 to $400,000.  The Company has recorded
$200,000 in deferred charges at September 30, 1999.

The Commission has approved a generic recovery mechanism for
costs incurred at all MGP sites, except recovery for the Concord
site noted above, which provides for a seven-year recovery period
of substantially all costs, excluding carrying costs. The
recovery mechanism provides that the environmental surcharge to
customers will not exceed 5% of total gross gas revenues in any
given year but that amounts in excess of 5% will be deferred to
future periods with recovery of applicable carrying costs.

The Company intends to pursue insurance recovery as well as
recovery from other responsible parties to ensure that such third
parties contribute appropriately to reimburse the Company for any
costs incurred with respect to environmental matters.  All
recoveries serve to reduce the seven-year environmental surcharge
period to customers.  The Company has instituted suits in the
United States Federal District Court for New Hampshire and in New
Hampshire superior courts against one third party, as well as the
Company's insurers and insurers of its predecessors to recover
the costs of investigation and remediation of the Concord,
Nashua, Dover and Laconia MGP sites.  In each litigation, the
Company is seeking declaratory judgment that its insurers owe the
Company a defense and/or indemnification for environmental claims
associated with each respective MGP.  Through September 30, 1999,
the Company has recovered a total of $4.3 million in settlement
of third-party MGP litigation.

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 1999.



<PAGE>




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 1999 and 1998 were as follows:


                                Fiscal 1999             Fiscal 1998
                           High         Low         High        Low
-------------------------------------------------------------------
First Quarter           $29 5/8    $26 3/16    $28 13/16    $22 3/4
Second Quarter           30 1/8     27 1/2      29 1/16      27 5/8
Third Quarter            29 1/4     26 5/8      29 3/4       26 3/8
Fourth Quarter           43 3/4     28 7/8      27 5/8       25 1/4

As of December 2, 1999, there were 1,839 holders of record of common
stock.

Quarterly cash dividends paid were as follows:

                                Fiscal 1999           Fiscal 1998
-----------------------------------------------------------------
First Quarter                         $.335                 $.32
Second Quarter                         .335                  .32
Third Quarter                          .35                   .335
Fourth Quarter                         .35                   .335


<TABLE>
<CAPTION>

ITEM 6.  SELECTED FINANCIAL DATA

(In thousands, except per share amounts)
September 30,                                                1999         1998         1997         1996         1995
---------------------------------------------------------------------------------------------------------------------
<C>                                                      <S>          <S>          <S>          <S>          <S>
Total operating revenues                                 $119,172     $109,926     $105,871     $ 88,954     $ 78,806

Net income                                                  4,537        5,378        6,518        6,078        4,104

Earnings per share                                           1.37         1.64         2.01         1.89         1.30

Cash dividends per share                                     1.37         1.31         1.25         1.19         1.12

Total assets                                              168,325      154,394      138,800      132,098      120,678

Capitalization:
 Common stockholders' equity                               50,943       50,890       47,722       45,167       42,114
 Long-term debt (including capital lease obligations)      45,679       44,390       45,242       29,571       30,103
                                                         ------------------------------------------------------------
  Total capitalization                                   $ 96,622     $ 95,280     $ 92,964     $ 74,738     $ 72,217
                                                         ============================================================

Short-term debt (including current portion of
 long-term debt)                                         $ 16,069     $  5,585     $  1,078     $ 11,854     $  5,501

-------------------------

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

</TABLE>





<PAGE>


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

Earnings and Dividends

Earnings per share for 1999 were $1.37 on net income of $4.5
million, which represents a 16.5% decrease from the $1.64 per
share earned in 1998.  Impacting 1999 financial results were
reorganization costs of $1.2 million, or $.35 per share, incurred
as a result of the pending merger with Eastern.  Although the
weather was colder in 1999, it was warmer than normal and also
had a significant impact on financial results, reducing 1999
utility margin by approximately $.36 per share, after taxes.  In
1998, utility margin was reduced approximately $.51 per share,
after taxes, as a result of warmer than normal temperatures.  The
1999 earnings were favorably impacted by continued customer
growth and successful efforts to contain operating costs. The
earnings achieved represent a return on average common equity of
11.2% before the impact of reorganization costs.  Cash dividends
paid on common stock were $1.37 representing a payout ratio of
100% of 1999 earnings. The current quarterly dividend of $.35 per
share is equal to an annual dividend of $1.40 per share.  The
quarterly dividend increased 4.5% in 1999, from $.335 to $.35 per
share.

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 ENGI to charge rates that are just and reasonable, such
that ENGI is compensated for the cost of providing service and
allowed a reasonable rate of return on its investment.  ENGI
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.

ENGI generates revenues primarily through the sale and
transportation of natural gas.  ENGI's gas sales are divided into
two categories:  firm, whereby ENGI must supply gas to customers
on demand; and interruptible, whereby ENGI  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 ENGI's operating
income because all margin on such sales is returned to the
Company's firm customers.

ENGI's tariff includes cost of gas 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 cost
of gas rates affect revenues, they do not affect total margin
because the cost of gas charge is a tariff mechanism designed to
provide dollar-for-dollar recovery of gas costs.  Amounts
recovered through cost of gas charges are reconciled at least
semiannually against actual costs, and future cost of gas rates
are adjusted accordingly.

ENGI's sales are responsive to colder weather because the
majority of firm customers use natural gas for space heating
purposes.  ENGI 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



<PAGE>




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
ENGI's service territory, weather conditions within such territory
often vary.  ENGI 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, 1999    6,698       6,532     7,452         2.5 %     (10.1)%
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)%

</TABLE>

Operating revenues for ENGI were $76.6 million in 1999 compared
to $85.3 million in 1998.  The decrease resulted primarily from
lower cost of gas rates due to reductions in the cost of gas.
Partially offsetting the impact of lower cost of gas charges was
the 2.4% growth in the average number of customers in 1999.
Customer growth combined with temperatures that were 2.5% colder
than the prior year resulted in a 4.6% increase in firm sendout.
The weather in 1999 was 10.1% warmer than normal. Revenues from
gas transported for customers under firm transportation service
rates increased 45% to $3.4 million, due to a more than 46%
increase in volumes transported.  This increase included a shift
of 174,000 Mcf from firm commercial and industrial sales
customers, representing a decrease of $615,000 in operating
revenues attributable to the commodity cost of gas.

Utility Cost of Gas

The cost of gas sold was $36.6 million in 1999 compared to $46.7
million in 1998  The decrease was primarily due to timing
differences related to the recovery of gas costs through cost of
gas charges ($5.4 million), lower volumes of gas sold ($1.3
million) and a decline in the unit cost ($3.4 million).  The
average unit cost of gas sold in 1999 was $3.78 per Mcf compared
to $4.09 per Mcf in 1998.  Decreases or increases in purchased
gas costs from suppliers have no significant impact on margin,
because they are passed on to customers through the cost of gas
charge.

Retail Propane Operations

ENPI contributed $203,000 to net earnings of the Company, a
slight increase over 1998 results.  Significantly impacting net
earnings were reorganization costs of $95,000.  In addition,
ENPI's share of VGSP's loss was $266,000 after taxes compared to
a loss of $244,000 last year.  The average number of propane
customers increased more than 8% and propane gallons sold
increased 6.5% in 1999.  The substantial customer growth and
weather that was colder than the prior year accounted for the
increase in gallons sold. While 1999 operating revenues of $11.1
million were slightly less than 1998, gross margin increased
6.5%.  The cost of gas sold was favorably impacted by market
prices and was 7.5% less than 1998.  The Company was able to
maintain a competitive price while the unit cost of gas sold
decreased 13.2%.  Operations and maintenance expense increased
approximately 5.7%.  Increases in labor, transportation and other
delivery related



<PAGE>




expenses necessary to support an expanding customer base were partially
offset by cost control measures in other areas.

Mechanical Contracting Operations

Contract revenues and net income for 1999 were $31.4 million and
$422,000 compared to $13.4 million and $194,000 in 1998,
respectively.  The Company's mechanical contracting operations
were acquired under the purchase method of accounting in May
1998.  Consequently, only five months of ENMI are included in
1998 results.

Operating Expenses

Operation and maintenance expenses of the mechanical contracting
business and increases in wages were the primary reasons for the
9.3% increase in operations and maintenance in 1999.  The 1999
results include the first full year of ENMI operational expenses.

Higher depreciation and amortization charges were a direct result
of plant additions and amortization of environmental remediation
costs.  Net additions to property, plant and equipment were $13.8
million and $14.7 million in 1999 and 1998, respectively.

Total interest expense increased $210,000 in 1999 due primarily
to the increased level of short-term debt outstanding during the
fiscal year.

Reorganization costs are not currently tax deductible.  The
higher level of income before reorganization costs was the reason
for the $120,000 increase in federal and state income taxes in
1999.

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 1999 were capital
expenditures of $13.8 million, environmental remediation of $4.9
million, and retirement of $2.3 million of long-term debt.  In
addition, dividend payments to shareholders totaled $4.5 million
in 1999. These expenditures were funded primarily through cash
generated from current operations and short-term borrowings.
Borrowings against lines of credit during 1999 ranged from
$181,000 to a high of $15.3 million.  In addition, at September
30, 1999, deferred gas cost was in an undercollected position
resulting from winter and summer activity.  The undercollected
amounts will be recovered from customers through cost of gas
charges.




<PAGE>




Capital expenditures for fiscal year 2000 are currently projected
at approximately $14.3 million.  Additional cash requirements
will be necessary for the payment of dividends, environmental
remediation, annual sinking fund requirements, maturities of long-
term debt, working capital and costs related to the proposed
merger with Eastern.  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, 1999, the Company had available lines of credit
aggregating $27.7 million, $15.3 million of which was
outstanding.  In addition, a credit line of $10.5 million was
available at September 30, 1999, under the Company's fuel
inventory trust financing plan.  At September 30, 1999, the
Company's fuel inventory in trust was $8.3 million with an
outstanding purchase obligation of $8.3 million.

On September 30, 1999, the Company's capitalization ratio
consisted of 45% common equity and 55% 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 12 to the consolidated
financial statements.

Results of Operations 1998 Compared to 1997

Net income decreased to $5.4 million in 1998 from 1997 net income
of $6.5 million.  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.  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.

Operating revenues were $109.9 million in 1998, an increase of
3.9% from 1997.  Mechanical contracting operations acquired in
1998 added $13.4 million to operating revenues.  Utility gas
service revenues, which represented more than 77% of total
operating revenues, decreased by $7.7 million, or 8.3%.  The unit
cost of gas sold in 1998 was $4.09 per Mcf compared to $4.28 per
Mcf in 1997.  Although the weather in the Company's service
territory was 12.9% warmer than normal and 11.4% warmer than
1997, the total volume of gas delivered to utility customers
increased slightly.  Partially offsetting the impact of the
warmer temperatures was the 2.4% growth in the average number of
utility customers.

Propane operations recorded $11.2 million in total operating
revenues in 1998, a decrease over 1997 of $1.7 million.  Propane
gallons sold were slightly less than 1997 due to the warmer
weather, and the unit cost of propane gallons sold decreased 22%.




<PAGE>




Operations and maintenance expense for 1998 included the expenses
of the mechanical contracting operations  that  were  acquired
in  May.  The  increase  from  1997  was  due  mostly  to  this
acquisition.  Taxes other than income taxes increased $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.

New Accounting Standards and Pronouncements

During fiscal year 1999, the Company implemented a number of
Statements of Financial Accounting Standards (SFAS).  SFAS No.
130, "Reporting Comprehensive Income," establishes standards for
reporting and the disclosure of comprehensive income and its
components.  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.  SFAS No. 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
or recognition of those plans.  None of the above standards had a
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. 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 was to be effective in the first quarter of fiscal
year 2000, but was amended by SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133" - an amendment of FASB
Statement 133.  As such, SFAS No. 133 will be effective in the
first quarter of fiscal year 2001.  The Company has not yet
quantified the impacts of adopting SFAS No. 133 in the financial
statements and has not determined the timing of or method of
adoption of SFAS No. 133.  However, the statement could increase
volatility in earnings and other comprehensive income.

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.  At
September 30, 1999, all Company systems critical to the delivery
of gas to customers are year 2000 compliant.  All necessary
program modifications and system upgrades and testing have been
completed.  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.





<PAGE>





The Company is currently assessing year 2000 issues with third
parties with whom it has a material relationship.  Although this
assessment is ongoing, critical vendors contacted to date have
indicated that interruption to service due to year 2000 problems
is unlikely.  Due to the complexity of the problem and the
reliance on certain important vendors and suppliers, there can be
no guarantee that year 2000 compliance for all computer systems
and other systems will be achieved or that critical and important
vendors and suppliers will achieve compliance.  The successful
upgrade of the Company's systems on a timely basis is critical to
enable the Company to avoid business disruption and the loss of
essential information or data in the year 2000.  In addition, a
disruption of the transmission of gas due to year 2000 problems
experienced by the Company's  gas supplier or other significant
vendors and service providers could prevent the delivery of a
sufficient amount of gas to enable the Company to serve certain
customer segments.

Because of the difficulty of accessing year 2000 readiness of
others outside the control of the Company, the Company considers
potential disruptions by these third parties to present the
"reasonably likely worst case scenario."  The Company's inability
to serve its customers could result in increased costs, loss of
business and other similar risks.  In an effort to reduce the
risks of non-compliance, the Company has updated its Emergency
Plan to consider any foreseeable year 2000 contingencies.

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 discussion of the Company's business
and Management's Discussion and Analysis of Financial Condition
and Results of Operations include forward-looking statements
concerning the impact of changes in the cost of gas and cost of
gas rates on total margin; projected capital expenditures and
sources of cash to fund expenditures; the impact of regulatory
proceedings on unbundling; year 2000 readiness; estimated costs
of environmental remediation and regulatory approval of recovery;
competition with other forms of energy; expansion of service in
Berlin; the merger with Eastern; and customer bypass.  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 and other regulatory assets; weather; results
of regulatory proceedings on unbundling; impact of new pipeline
supplies; costs of other sources of energy; expansion of service
in Berlin; consummation of the merger with Eastern; customer
bypass; and success of the Company's year 2000 readiness efforts
and those of its vendors and customers.


ITEM  7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
           RISK

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




<PAGE>

<TABLE>
<CAPTION>


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,              1999         1998         1997
-----------------------------------------------------------------------------
<C>                                        <S>          <S>          <S>
Operating revenues                         $119,172     $109,926     $105,871

Operating expenses:
 Cost of sales                               69,321       64,124       61,829
 Operations and maintenance                  25,219       23,073       21,658
 Depreciation and amortization                7,647        6,604        6,153
 Taxes other than income taxes                4,142        4,072        2,876
 Federal and state income taxes               3,222        3,102        3,808
                                           ----------------------------------
   Total operating expenses                 109,551      100,975       96,324
                                           ----------------------------------

Operating income                              9,621        8,951        9,547

Other income                                  1,056        1,173          956

Reorganization cost                           1,184            -            -

Interest expense:
 Interest on long-term debt                   3,885        3,897        2,917
 Other interest                               1,071          849        1,068
                                           ----------------------------------
   Total interest expense                     4,956        4,746        3,985
                                           ----------------------------------
Net income                                 $  4,537     $  5,378     $  6,518
                                           ==================================

Earnings per share:
 Basic                                     $   1.37     $   1.64     $   2.01
 Diluted                                       1.36         1.64         2.01

Weighted average shares outstanding:
 Basic                                        3,319        3,273        3,243
 Diluted                                      3,333        3,273        3,243




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,                                                                        1999         1998
------------------------------------------------------------------------------------------------------
<C>                                                                              <S>          <S>
Assets
 Property:
   Utility plant, at cost                                                        $169,856     $158,595
   Accumulated depreciation and amortization                                       56,126       51,313
                                                                                 ---------------------
     Net utility plant                                                            113,730      107,282
   Net nonutility property, at cost                                                 8,049        7,771
                                                                                 ---------------------
     Net property                                                                 121,779      115,053
                                                                                 ---------------------
 Current assets:
   Cash and temporary cash investments                                                853        1,231
   Accounts receivable (net of allowances of $1,115 in 1999 and $1,127 in 1998)     9,810        9,727
   Unbilled revenues                                                                  559          516
   Deferred gas costs                                                               1,524            -
   Materials and supplies                                                           2,047        2,086
   Supplemental gas supplies                                                        9,723        9,653
   Prepaid and deferred taxes                                                       2,235        1,804
   Recoverable FERC 636 transition costs                                                -          252
   Prepaid expenses and other                                                       1,669        1,496
                                                                                 ---------------------
     Total current assets                                                          28,420       26,765
                                                                                 ---------------------
  Deferred charges and other assets:
   Regulatory asset - income taxes                                                  2,465        2,401
   Recoverable environmental costs                                                 11,646        6,113
   Other deferred charges                                                           2,156        1,941
   Other assets                                                                     1,859        2,121
                                                                                 ---------------------
     Total deferred charges and other assets                                       18,126       12,576
                                                                                 ---------------------
Total assets                                                                     $168,325     $154,394
                                                                                 =====================
Stockholders' equity and liabilities
  Capitalization (see accompanying statements)                                   $ 96,622     $ 95,280
                                                                                 ---------------------
  Current liabilities:
   Notes payable to banks                                                          15,278        3,524
   Current portion of long-term debt                                                  791        2,061
   Inventory purchase obligation                                                    8,329        8,712
   Accounts payable                                                                11,983       10,431
   Deferred gas costs                                                                   -        3,841
   Accrued interest                                                                   251          272
   Accrued and deferred taxes                                                         571          342
   Accrued FERC 636 transition costs                                                    -          252
   Accrued environmental remediation costs                                          4,132        2,345
   Customer deposits and other                                                      3,108        3,005
                                                                                 ---------------------
     Total current liabilities                                                     44,443       34,785
                                                                                 ---------------------
Commitments and contingencies
Deferred credits:
   Deferred income taxes                                                           21,254       18,828
   Unamortized investment tax credits                                               1,487        1,610
   Regulatory liability - income taxes                                              1,027        1,141
   Long-term environmental remediation costs                                          700            -
   Contributions in aid of construction and other                                   2,792        2,750
                                                                                 ---------------------
     Total deferred credits                                                        27,260       24,329
                                                                                 ---------------------
Total stockholders' equity and liabilities                                       $168,325     $154,394
                                                                                 =====================



     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,                                                      1999         1998
------------------------------------------------------------------------------------
<C>                                                            <S>          <S>
Capitalization:
 Common stockholders' equity:
  Common stock - par value of $1 per share; 10,000,000
    shares authorized; 3,319,718 and 3,317,498 shares
    issued and outstanding in 1999 and 1998, respectively      $  3,320     $  3,317
  Amount in excess of par value                                  32,506       32,445
  Retained earnings                                              15,117       15,128
                                                               ---------------------
      Total common stockholders' equity                          50,943       50,890
                                                               ---------------------

  Long-term debt:
   First Mortgage Bonds
     Due 2009                                  8.44%              3,333        3,667
     Due 2019                                  9.70%              7,000        7,000
     Due 2020                                  9.75%             10,000       10,000
     Due 2027                                  7.40%             21,955       21,975

  Mortgage notes payable
     Due 1999                                  8.75%                  -        1,300
     Due 2008                                  8.00%                833          899

  Promissory note
     Due 2009                       LIBOR plus 1.50%              2,463            -

  Notes payable
     Due 2000                                  prime                  -          700
     Due through 2001               prime plus 1.00%                 13           26
     Due through 2003                  .90% - 10.90%                228          279
     Due through 2004                prime plus .50%                645          605
                                                                --------------------
                                                                 46,470       46,451
  Less current portion                                              791        2,061
                                                                --------------------
       Total long-term debt                                      45,679       44,390
                                                                --------------------
Total capitalization                                            $96,622      $95,280
                                                                ====================


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, 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

Net income                                                    -                 -           4,537             4,537
Common Stock - cash dividend ($1.37 per share)                -                 -          (4,548)           (4,548)
Issuance of common stock under the Key Employee
  Performance and Equity Incentive Plan                       3                61               -                64
                                                         ----------------------------------------------------------
Balance, September 30, 1999                              $3,320           $32,506         $15,117           $50,943
                                                         ==========================================================


        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,                                      1999         1998          1997
------------------------------------------------------------------------------------------------------
<C>                                                                <S>          <S>           <S>
Cash flows from operating activities:
 Net income                                                        $  4,537     $  5,378      $  6,518
 Noncash items:
  Depreciation and amortization                                       8,238        7,152         6,869
  Deferred taxes and investment tax credits, net                      2,098          345         1,521
 Changes in:
  Accounts receivable, net                                              (83)       1,066        (1,401)
  Unbilled revenues                                                     (43)          86           (20)
  Inventories                                                           (31)        (472)         (247)
  Prepaid expenses and other                                            585          784           434
  Deferred gas costs                                                 (5,365)       2,541         5,083
  Accounts payable                                                    1,552         (728)         (143)
  Accrued liabilities                                                  (202)         460           366
  Accrued/prepaid taxes                                                (202)        (400)       (1,233)
 Payments for environmental costs and other                          (4,132)      (1,242)       (3,104)
                                                                   -----------------------------------
    Net cash provided by operating activities                         6,952       14,970        14,643
                                                                   -----------------------------------
Cash flows from investing activities:
  Additions to property                                             (13,834)     (14,716)      (13,262)
  Change in note receivable, net                                          -          131           (72)
  Other investing activities                                              -          249             -
                                                                   -----------------------------------
    Net cash used for investing activies                            (13,834)     (14,336)      (13,334)
                                                                   -----------------------------------

Cash flows from financing activities:
  Issuance of common stock                                               64           99            91
  Cash dividends on common stock                                     (4,548)      (4,300)       (4,054)
  Issuance of long-term debt                                          2,296          646        22,616
  Repayment of long-term debt                                        (2,277)      (1,338)       (8,055)
  Repayment of capital lease obligations                                  -          (46)         (229)
  Change in notes payable to banks                                   11,754        3,392        (9,435)
  Change in inventory purchase obligation                              (383)         860           (15)
  Change in other financing activities                                 (402)        (714)       (1,000)
                                                                   -----------------------------------
    Net cash provided by (used for) financing activities              6,504       (1,401)          (81)
                                                                   -----------------------------------

Net (decrease) increase in cash and temporary cash investments         (378)        (767)        1,228
Cash and temporary cash investments, begining of year                 1,231        1,998           770
                                                                   -----------------------------------
Cash and temporary cash investments, end of year                   $    853     $  1,231      $  1,998
                                                                   ===================================



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


</TABLE>





ENERGYNORTH, INC.
Notes to Consolidated Financial Statements

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., primarily 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 10).

Business Segments
-----------------

Effective October 1, 1998, the Company adopted SFAS No. 131,
"Disclosure about Segments of an Enterprise and Related
Information."  Pursuant to SFAS No. 131, the Company's three
reportable segments are natural gas distribution, propane gas
distribution and mechanical contracting.  The adoption of this
statement by the Company did not have a material effect on the
Company's financial statements.  In accordance with this
statement, the Company is presenting the required information for
the three segments.  Because this is the initial year of
application of this statement, comparative information for prior
years was restated.



<PAGE>

<TABLE>
<CAPTION>

Segment information including operating results and other financial data is presented below:

(In thousands)                                                   1999         1998         1997
-----------------------------------------------------------------------------------------------
<C>                                                          <S>          <S>          <S>
Revenues:
   Natural gas distribution                                  $ 76,617     $ 85,296     $ 92,978
   Propane gas distribution                                    11,164       11,204       12,893
   Mechanical contracting                                      31,391       13,426            -
                                                             ----------------------------------
                                                             $119,172     $109,926     $105,871
                                                             ==================================
Operating income, before income taxes:
   Natural gas distribution                                  $ 11,380     $ 11,039     $ 12,389
   Propane gas distribution                                       764          631          793
   Mechanical contracting                                         509          231            -
   Other                                                          190          152          173
                                                             ----------------------------------
                                                             $ 12,843     $ 12,053     $ 13,355
                                                             ==================================
Identifiable assets, net of depreciation and reserves:
   Natural gas distribution                                  $150,757     $136,775     $131,261
   Propane gas distribution                                     8,543        8,695        7,069
   Mechanical contracting                                       9,012        8,391            -
   Other                                                           13          534          470
                                                             ----------------------------------
                                                             $168,325     $154,395     $138,800
                                                             ==================================
Capital expenditures:
   Natural gas distribution                                  $ 12,081     $ 13,152     $ 11,977
   Propane gas distribution                                     1,604        1,295        1,281
   Mechanical contracting                                         142          142            -
   Other                                                            7          127            4
                                                             ----------------------------------
                                                             $ 13,834     $ 14,716     $ 13,262
                                                             ==================================
Depreciation and amortization:
   Natural gas distribution                                  $  6,322     $  5,381     $  4,969
   Propane gas distribution                                     1,064        1,042        1,107
   Mechanical contracting                                         185          104            -
   Other                                                           76           77           77
                                                             ----------------------------------
                                                             $  7,647     $  6,604     $  6,153
                                                             ==================================
Interest expense:
   Natural gas distribution                                  $  4,606     $  4,425     $  3,718
   Propane gas distribution                                       230          214          178
   Mechanical contracting                                          49           30            -
   Other                                                           71           77           89
                                                             ----------------------------------
                                                             $  4,956     $  4,746     $  3,985
                                                             ==================================
Income tax provision:
   Natural gas distribution                                  $  2,740     $  2,812     $  3,478
   Propane gas distribution                                       187          124          288
   Mechanical contracting                                         237          123            -
   Other                                                           58           43           42
                                                             ----------------------------------
                                                             $  3,222     $  3,102     $  3,808
                                                             ==================================
</TABLE>

<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 Rates
-----------------

The Company's tariff includes a cost of gas rate that permits
billings to customers to recover its cost of gas.  The tariff
provides for a cost of gas rate calculation for a summer period
and a winter period.  The Company may adjust the approved cost of
gas 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
3.5% for the year ended September 30, 1999, and 3.4% for each of
the years ended September 30, 1998 and 1997.  The depreciation
rates for nonregulated property, plant and equipment were 7.4%,
7.5% and 8% for the years ended September 30, 1999, 1998 and
1997, 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.




<PAGE>




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, 1999, regulatory assets included $11.6
million for environmental investigation and remediation costs and
$2.5 million of unrecovered deferred state income taxes (see Note 7).


The unamortized cost of issuing debt at September 30, 1999 is
$1.9 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, 1999 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, 1999 accompanying consolidated balance sheet by 2%.


Stock-Based Compensation
------------------------

The Company has elected to follow Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" (APB
25) and related interpretations in accounting for its employee
stock options.  Under APB 25, because the exercise price of
employee stock options equals the market price of the underlying
stock on the date of grant, no compensation expense is recorded.
The Company has adopted the disclosure-only provisions of SFAS
No. 123, "Accounting for Stock-Based Compensation" (see Note 9).

Comprehensive Income
--------------------

Effective October 1, 1998, the Company adopted SFAS No. 130,
"Reporting Comprehensive Income."  This statement establishes
standards for reporting and the disclosure of comprehensive
income and its components.  It did not have a material impact on
the Company's financial reporting.




<PAGE>





Earnings per Share
------------------

SFAS No. 128, "Earnings per Share," requires the computation of
basic and diluted earnings per share.  Basic earnings per share
is computed by dividing net income by the weighted average number
of shares of common stock outstanding during the year.  Diluted
earnings per share is determined by giving effect to the exercise
of stock options using the treasury stock method (see Note 9).


(In thousands, except per share amounts)
For the years ended September 30,              1999       1998       1997
-------------------------------------------------------------------------
Net income                                   $4,537     $5,378     $6,518
                                             ============================

Weighted average shares                       3,319      3,273      3,243
Dilutive effect of options                       14          -          -
                                             ----------------------------
Adjusted weighted average shares              3,333      3,273      3,243
                                             ============================

Basic earnings per share                     $ 1.37     $ 1.64     $ 2.01
Diluted earnings per share                   $ 1.36     $ 1.64     $ 2.01


Derivative Instruments and Hedging Activities
---------------------------------------------

The Company utilizes call and put option 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 traded on the NYMEX are included in the table
below, they are not financial instruments since physical delivery
of natural gas may be made pursuant to these contracts.  They are
a major part of the commodity risk management program.

The following table summarizes the types of hedges used and the
related financial information as of September 30, 1999:

Notional volumes         Hedges of                NYMEX contracts
-----------------------------------------------------------------
Calls - MMBtu            Purchases                            105
Puts - MMBtu             Sales                                105

$ Amount (In thousands)
-----------------------------------------------------------------
Deferred losses, net                                         $(16)


<PAGE>


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):

                                             1999       1998       1997
-----------------------------------------------------------------------
Cash paid during the year for:
 Interest (net of amount capitalized)      $4,683     $4,269     $4,080
 Income taxes                                 981      3,246      3,972

Noncash investing and financing activities:
 Acquisition investment (see Note 10)           -      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
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 cost of gas charge.

The bank credit agreement provides for a .375% commitment fee on
the credit line and interest at prime (8.25% at September 30,
1999) 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 March 31, 2001.

As of September 30, 1999 and 1998, the gas inventories under the
trust agreement and controlled by the Company totaled $8.3
million and $8.7 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.




<PAGE>




Note 4.  Notes Payable to Banks

As of September 30, 1999, the Company had $27.7 million available
under various unsecured bank lines of credit that are renewed
annually, $15.3 million of which was outstanding.  The weighted
average interest rate on borrowings outstanding on September 30,
1999 was 6.1%.  The lines bear interest at prime or less than
prime on certain of the lines for fixed periods of time, and are
due on demand.  For some lines, the terms of the credit
agreements require annual commitment fees of .25% 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, 1999 are as
follows (in thousands):

                        Fiscal year                        Amount
-----------------------------------------------------------------
                        2000                                 $791
                        2001                                  666
                        2002                                  563
                        2003                                  505
                        2004                                  459


Note 6.  Common Stock

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

In the event the Company is acquired in a merger or other
business combination, 50% or more of its consolidated assets or
earning power is sold or transferred, any person acquires 15% or
more of the Company's outstanding common stock, or an Acquiring
Person engages in one or more self-dealing transactions with the
Company, each Right will entitle its holder to purchase, at the
Rights' exercise price, a number of shares of common stock of the
Company or of the acquiring company having a value of twice such
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



<PAGE>




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, 1999 and 1998, a SFAS No. 109 related regulatory
liability amounted to $824,000 and $892,000, respectively, for
the tax benefit of unamortized investment tax credits, and
$203,000 and $249,000, 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 $2.5 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.

The tax effects of cumulative differences that gave rise to the
deferred tax liabilities and deferred tax assets for the years
ended September 30, 1999 and 1998 were as follows (in thousands):

                                           1999          1998
-------------------------------------------------------------
Deferred tax assets:
 Deferred gas costs                      $    -       $ 1,450
 Contributions in aid of construction       794           759
 Unamortized investment tax credits         506           545
 Allowance for doubtful accounts            429           434
 Deferred compensation                      367           280
 VEBA                                       175           119
 Other                                      365           886
                                         --------------------
   Total deferred tax assets              2,636         4,473
                                         ====================

Deferred tax liabilities:
 Property-related                        19,110        18,035
 Environmental costs                      2,645         1,455
 Other                                    2,067         2,073
                                        ---------------------
   Total deferred tax liabilities        23,822        21,563
                                        ---------------------
Net deferred tax liability              $21,186       $17,090
                                        =====================



<PAGE>




Deferred income taxes were classified in the accompanying consolidated
balance sheets at September 30, 1999 and 1998 as follows (in thousands):

                                                      1999         1998
-----------------------------------------------------------------------
Current                                            $   (68)     $(1,738)
Long-term                                           21,254       18,828
                                                   --------------------
    Total                                          $21,186      $17,090
                                                   ====================

The components of federal and state income taxes reflected in the accompanying
consolidated statements of income for the years ended September 30, 1999, 1998
and 1997 were as follows (in thousands):

                                           1999        1998        1997
-----------------------------------------------------------------------
Federal:
  Current                                $ (213)     $2,939      $3,649
  Deferred                                2,983        (265)       (383)
  Investment tax credits                   (123)       (124)       (136)
                                         ------------------------------
    Total federal                         2,647       2,550       3,130
                                         ------------------------------

State:
  Current                                  (196)        601         756
  Deferred                                  771         (49)        (78)
                                         ------------------------------
    Total state                             575         552         678
                                         ------------------------------
Total provision for income taxes         $3,222      $3,102      $3,808
                                         ==============================

The total federal and state income tax provision, as a percentage of
income before federal and state income taxes, was 41.5%, 36.6% and
36.9% for the years ended September 30, 1999, 1998 and 1997, respectively.
The significant increase in the effective federal and state income tax
rate is due to reorganization costs that are not tax deductible.  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):


<TABLE>

                                                            1999       1998       1997
--------------------------------------------------------------------------------------
<C>                                                       <S>        <S>        <S>
Tax calculated at statutory rate                          $2,638     $2,883     $3,511
Increase (reduction) in effective tax resulting from:
  Amortization of investment tax credit                     (123)      (124)      (136)
  Adjustment due to change in tax rates                      (28)       (28)       (28)
  State taxes, net of federal tax benefit                    380        364        447
  Reorganization costs                                       403          -          -
  Other, net                                                 (48)         7         14
                                                          ----------------------------
Total provision for income taxes                          $3,222     $3,102     $3,808
                                                          ============================

</TABLE>

<PAGE>




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.

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 1999, 1998 and 1997 for providing postretirement
benefits, including amortization of the accumulated projected benefit obligation
over a 20-year period, was $413,000, $486,000 and $542,000, respectively.

The Company has funded these benefit costs by making cash contributions, at the
same level of expense recorded, to voluntary employee benefit association (VEBA)
trusts established separately for salaried and hourly paid employees.

<TABLE>
<CAPTION>

(In thousands)                                               Pension             Medical and life
                                                       ------------------------------------------
For the years ended                                    1999          1998        1999        1998
-------------------------------------------------------------------------------------------------
<C>                                                 <S>           <S>          <S>         <S>
Change in benefit obligation:
 Benefit obligation at beginning of year            $22,446       $18,966      $5,279      $5,213
 Service cost                                           822           684         132         123
 Interest cost                                        1,543         1,397         362         385
 Participant contributions                                -             -           -           -
 Plan amendments                                        242             -           -           -
 Benefits paid                                         (923)         (809)       (267)       (210)
 Actuarial (gain) or loss                            (1,776)        2,208        (514)       (232)
                                                    ---------------------------------------------
 Benefit obligation at end of year                  $22,354       $22,446      $4,992      $5,279
                                                    =============================================

Change in plan assets:
 Fair value of plan assets at beginning of year     $21,316       $21,018      $3,013      $2,555
 Actual return on plan assets                         2,058           442         225         180
 Employer contributions                                 681           665         421         488
 Participant contributions                                -             -           -           -
 Benefits paid                                         (923)         (809)       (267)       (210)
                                                    ---------------------------------------------
 Fair value of plan assets at end of year           $23,132       $21,316      $3,392      $3,013
                                                    =============================================

</TABLE>


<PAGE>

<TABLE>
<CAPTION>


(In thousands)                                                  Pension                 Medical and life
                                                           ----------------------------------------------
 For the years ended September 30,                         1999          1998          1999          1998
---------------------------------------------------------------------------------------------------------
<C>                                                     <S>           <S>           <S>           <S>
Reconciliation of funded status:
 Funded status                                          $   778       $(1,129)      $(1,600)      $(2,266)
 Contributions between 7/31 and 9/30                          -            78           101           118
 Unrecognized actuarial (gain) or loss                     (577)        1,362        (2,224)       (1,826)
 Unrecognized transition (asset) of obligation              (87)         (107)        3,661         3,922
 Unrecognized prior service cost                            607           453             -             -
                                                        -------------------------------------------------
 Net amount recognized at year end                      $   721       $   657       $   (62)      $   (52)
                                                        =================================================

Amounts recognized in the statements of
financial position consist of:
 Prepaid benefit cost                                   $ 2,355       $ 2,014       $     1       $     1
 Accrued benefit liability                               (1,880)       (1,686)          (63)          (53)
 Intangible asset                                           161           256           N/A           N/A
 Accumulated other comprehensive income                      85            73           N/A           N/A
                                                        -------------------------------------------------
 Net amount recognized at year end                      $   721       $   657       $   (62)      $   (52)
                                                        =================================================

Additional year-end information for plans
with benefit obligations in excess of plan
assets:
 Benefit obligation                                     $ 2,503       $ 2,326       $ 4,992       $ 5,279
 Fair value of plan assets                                    -             -         3,392         3,013

Additional year-end information for pension
plans with accumulated benefit obligations
in excess of plan assets:
 Projected benefit obligation                          $  2,506       $ 2,326           N/A           N/A
 Accumulated benefit obligation                           1,880         1,686           N/A           N/A
 Fair value of plan assets                                    -             -           N/A           N/A

Components of net periodic benefit cost:
 Service cost                                          $    822       $   684       $   132       $   123
 Interest cost                                            1,543         1,397           362           385
 Expected return on plan assets                          (1,939)       (1,684)         (240)         (199)
 Amortization of prior service cost                          88            88             -             -
 Amortization of transitional (asset) or obligation         (20)          (20)          261           261
 Recognized actuarial (gain) or loss                         45            31          (102)          (84)
                                                       --------------------------------------------------
 Net period benefit cost                               $    539       $   496       $   413       $   486
                                                       ==================================================
Weighted-average assumptions:
 Discount rate                                             7.50%         7.00%         7.50%         7.00%
 Expected long-term rate of return on plan assets          9.50%         9.50%         9.50%         9.50%
 Rate of compensation increase - salaried                  5.50%         5.50%         5.50%         5.50%
 Rate of compensation increase - hourly                    4.00%         4.00%         4.00%         4.00%

</TABLE>


The prior service cost is amortized on a straight-line basis over
the average remaining service period for active participants.
The gain or loss in excess of the greater of 10% of the benefit
obligation or the market value of assets is amortized on a
straight-line basis over the average remaining service period for
active participants.



<PAGE>




Assumed Health Care Cost Trend

For measurement purposes, an 8% annual rate of increase in the
per capita cost of covered health care benefits was assumed for
1999.  The rate is assumed to decrease gradually to 5% for 2002
and remain at that level thereafter.  For 1999, the annual rate
of increase for age post 65 was changed to 10% , decreasing
gradually to 5% for 2004 and thereafter.

Assumed health care cost trend rates have a significant effect on
the amounts reported for the health care plan.  A one-percentage-
point change in assumed health care costs trend rates would have
the following effects for 1999:

                                                One percentage   One percentage
                                                point increase   point decrease
                                                -------------------------------
Total of service and interest cost components         $ 18,913        $ (17,309)
Postretirement benefit obligation                      188,473         (174,449)


The Company has employee 401(k) savings and investment plans covering
substantially all employees.  The Company made contributions of
$263,000, $254,000 and $242,000 for the years ended September 30, 1999,
1998 and 1997, 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 1999.  The plan includes a
salary reduction provision with a matching discretionary employer
contribution.  The company contributed $34,000 in 1999.

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 $551,000 in
1999.

Note 9.  Stock Option Plan

During fiscal year 1999, the EnergyNorth, Inc. 1998 Stock Option
Plan (Plan) was adopted.  The Plan provides for grants of either
incentive stock  options or nonqualified stock options to
purchase shares of the Company's common stock.  Stock options may
be granted to officers, directors and key employees responsible
for the direction and management of the Company.  At September
30, 1999, 200,000 shares of common stock were reserved for
issuance under the Plan.  Information related to stock options
during 1999 is as follows:

                                       Number   Option exercise
                                    of shares   price per share   Total price
-----------------------------------------------------------------------------
Shares under option at 9/30/98             -             $    -    $        -
Granted                               44,000              28.00     1,232,000
Exercised                                  -                  -             -
Forfeited                                  -                  -             -
                                    -----------------------------------------
Shares under option at 9/30/99        44,000             $28.00    $1,232,000
                                    =========================================




<PAGE>




Outstanding options were incentive options and non-qualified
options.  No compensation expense related to stock option grants
was recorded in 1999 as the option exercise prices were equal to
fair market value on the date of grant.

Pro forma information regarding net income and earnings per share
is required by SFAS No. 123, "Accounting for Stock-Based
Compensation," and has been determined as if the Company had
accounted for its employee stock options under the fair value
method of that statement.  The fair value for these options was
estimated at the date of grant using a Black-Scholes option
pricing model with the following weighted average assumptions for
1999:

                                                            1999
----------------------------------------------------------------
Risk-free interest rate                                    4.45%
Dividend yield                                             3.30%
Volatility factor                                          .2353
Weighted average expected life                           4 years

The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting
restrictions and are fully transferable.  In addition, option
valuation models require the input of highly subjective
assumptions including the expected stock price volatility.
Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because
changes in the subjective input assumptions can materially affect
the fair value estimate, in management's opinion, the existing
models do not necessarily provide a reliable single measure of
the fair value of its employee stock options.  For purposes  of
pro  forma  disclosures, the estimated fair value of the options
is amortized to expense over the options' vesting periods.  The
Company's pro forma net earnings (in thousands) and earnings per
share were as follows:

                                                            1999
----------------------------------------------------------------
Net earnings - as reported                                $4,537
Net earnings - pro forma                                   4,504
Earnings per share - as reported                            1.37
Earnings per share - pro forma                              1.36
Weighted average fair value of options                      5.04
granted during the year

Because the statement provides for pro forma amounts for options
granted beginning in 1999, the pro forma expense will likely
increase in future years as new option grants become subject to
the pricing model.

Note 10.  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



<PAGE>




as a purchase.  Accordingly, the results of operations of NPI
and GSPH are included in the accompanying consolidated financial
statements since May 1, 1998.

Note 11.  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, 1999, are approximated as follows
(in thousands):

                        Fiscal year                        Amount
-----------------------------------------------------------------
                        2000                                 $322
                        2001                                  257
                        2002                                  223
                        2003                                   95
                        2004                                    9

The total rental expense charged to operations for the years
ended September 30, 1999, 1998 and 1997 was approximately
$611,000, $557,000 and $574,000, respectively.

Note 12. 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 cost of gas rates.  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, own or owned
several facilities at which manufactured gas plants (MGP)
operated.  MGPs were used to manufacture gas prior to the
introduction of natural gas to the Company's service area.
Generally, MGPs operated from the late 1800s to the early 1950s.
The MGPs produced wastes and by-products that may be considered
contaminated or hazardous under current law, and some of which
may still be present at such facilities.  Relevant environmental
laws can be used by the state and federal government to hold the
Company strictly liable for the costs of studying and remedying
discarded by-products from MGPs owned and operated by its
predecessors.  The Company accrues environmental investigation
and cleanup costs with respect to former MGPs and other
environmental matters when it is probable that a liability exists
and the amount or range of amounts can be reasonably estimated.




<PAGE>




The New Hampshire Department of Environmental Services (NHDES)
has required the Company to undertake remedial investigation
and/or remedial action at MGPs located in Concord, Laconia,
Nashua, and Dover, New Hampshire.  At each MGP, the Company is
responding to the NHDES's requirements as described below.

In September 1992, the NHDES required the Company to undertake a
remedial investigation of the former MGP in Concord, New
Hampshire.  Study and remediation associated with the Concord MGP
is ongoing.  The estimated cost to complete this remedial action
ranges from $690,000 to $1.6 million, and the Company has
recorded $690,000 at September 30, 1999 in deferred charges.  The
Company received an order from the Commission approving recovery
from customers, over a seven-year period, of substantially all
costs, excluding carrying costs, incurred for the Concord MGP.
The total unamortized balance for the Concord site, including the
gas holder site, was $4.4 million as of September 30, 1999.

At the direction of the NHDES, the Company and Public Service
Company of New Hampshire (PSNH), an electric utility company,
conducted a remedial investigation of a former MGP in Laconia,
New Hampshire, and in January 1999 prepared a Remedial Action
Plan for that site. Without admitting any liability, on September
3, 1999, the Company entered into a Site Responsibilities and
Indemnity Agreement (SRIA) with PSNH.  Pursuant to the SRIA, the
Company will pay $4.2 million to PSNH over a twenty-four (24)
month period.  In exchange, PSNH will assume responsibility for
all future site study and remediation, and PSNH will indemnify
the Company against such costs.  The Company's legal liability
under state and federal laws is unaffected by the SRIA.  Through
September 30, 1999, the Company has paid $1 million under the
SRIA.  The estimated costs associated with work undertaken prior
to the SRIA ranges from $117,000 to $517,000, and the Company has
recorded $3.3 million in deferred charges at September 30, 1999.

During 1998, the Company and PSNH received Notice of Potential
Responsibility from the Environmental Protection Agency (EPA) for
the so-called Nashua River Asbestos Site.  The EPA contends that
wastes released from the former MGP in Nashua, New Hampshire are
commingled with asbestos wastes from a former Johns Manville
facility located adjacent to the former MGP.  The Company's share
of costs to complete the disposal of contaminants that are the
subject of EPA claims are estimated to range from $375,000 to
$450,000.  The Company and PSNH subsequently received a notice
from the NHDES requiring the investigation of the former MGP site
in Nashua.  The Company estimates the cost of site investigation
and characterization at the Nashua MGP to range from $250,000 to
$325,000.  The Company recorded $625,000 in deferred charges at
September 30, 1999.

In April 1999, the Company received notice from the NHDES to
investigate the former MGP site in Dover, New Hampshire.  PSNH
and another utility company, Northern Utilities, received similar
notices concerning the Dover MGP from the NHDES.  The Company
estimates its cost of that investigation and characterization to
range from $200,000 to $400,000.  The Company has recorded
$200,000 in deferred charges at September 30, 1999.




<PAGE>




The Commission has approved a generic recovery mechanism for
costs incurred at all MGP sites, except recovery for the Concord
site noted above, which provides for a seven-year recovery period
of substantially all costs, excluding carrying costs. The
recovery mechanism provides that the environmental surcharge to
customers will not exceed 5% of total gross gas revenues in any
given year but that amounts in excess of 5% will be deferred to
future periods with recovery of applicable carrying costs.

The Company intends to pursue insurance recovery as well as
recovery from other responsible parties to ensure that such third
parties contribute appropriately to reimburse the Company for any
costs incurred with respect to environmental matters.  All
recoveries serve to reduce the seven-year environmental surcharge
period to customers.  The Company has instituted suits in the
United States Federal District Court for New Hampshire and in New
Hampshire superior courts against one third party, as well as the
Company's insurers and insurers of its predecessors to recover
the costs of investigation and remediation of the Concord,
Nashua, Dover and Laconia MGP sites.  In each litigation, the
Company is seeking declaratory judgment that its insurers owe the
Company a defense and/or indemnification for environmental claims
associated with each respective MGP.  Through September 30, 1999
the Company has recovered a total of $4.3 million in settlement
of third-party MGP litigation.

Note 13.  Merger

On July 14, 1999, the Company and Eastern Enterprises (Eastern),
a Massachusetts business trust, entered into an Agreement and
Plan of Reorganization (Agreement) which provides for the merger
of the Company with a subsidiary of Eastern, as a result of which
the Company's subsidiaries would become wholly owned subsidiaries
of Eastern.  On November 4, 1999, Eastern entered into an
agreement to merge with KeySpan Corporation and, as a result, the
Company and Eastern amended the Agreement.  Under the amended
Agreement, holders of outstanding shares of the Company's common
stock will be paid entirely in cash and the closing will take
place simultaneously with the Eastern merger with KeySpan
Corporation.  If the Eastern/KeySpan Corporation merger is not
completed, the Company and Eastern would nonetheless merge, and
holders of outstanding shares of the Company's common stock can
elect to receive cash, Eastern common stock or a combination of
cash and stock as set forth in the Agreement.  Completion of the
merger is subject to approval by the Company's stockholders and
receipt of satisfactory regulatory approvals, including approval
by the Commission and the Securities and Exchange Commission.
Reorganization costs incurred as a result of the impending merger
were $1.2 million in 1999.





<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, 1999
and 1998, 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, 1999. 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, 1999
and 1998, and the results of their operations and their cash
flows for each of the three years in the period ended September
30, 1999, 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 5, 1999




<PAGE>

<TABLE>
<CAPTION>

(b)  Supplementary Financial Information

Selected Quarterly Financial Data (Unaudited)                                    EnergyNorth, Inc.

(In thousands, except   Operating       Operating   Net income   Earnings (loss)     Cash dividend
per share amounts)       revenues   income (loss)       (loss)         per share    paid per share
---------------------------------- ---------------------------------------------------------------
<S>                       <S>             <S>          <S>                <S>                <S>
First Quarter
1999                      $31,471         $ 4,226      $ 3,219            $  .97             $.335
1998                       30,892           4,801        4,142              1.28              .32
--------------------------------------------------------------------------------------------------
Second Quarter
1999                      $47,985         $ 7,856      $ 7,115            $ 2.14             $.335
1998                       42,032           6,658        5,836              1.80              .32
--------------------------------------------------------------------------------------------------
Third Quarter
1999                      $21,655         $  (781)     $(1,821)           $ (.55)            $.35
1998                       20,498            (823)      (1,758)             (.54)             .335
--------------------------------------------------------------------------------------------------
Fourth Quarter
1999                      $18,061         $(1,680)     $(3,976)           $(1.19)            $.35
1998                       16,504          (1,685)       2,842              (.86)             .335



</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, 1999.




<PAGE>




                              PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Directors of the Registrant

The directors and executive officers who are directors of the Registrant are
listed below, together with position, age at December 31, 1999, business
experience, and other information as to each.


<TABLE>
<CAPTION>

Name and position                     Director    Officer         Principal occupation or employment
with the Registrant            Age     since       since                during last five years
------------------------------------------------------------------------------------------------------------------
<C>                             <S>    <S>         <S>        <S>
Roger C. Avery                  60     1984                   President and Chief Executive Officer,
                                                              Illinois Gas Company; Adjunct Associate
                                                              Professor, Brown University

Edward T. Borer (1)             61     1982                   Retired; formerly (until 1999) Chairman
  Chairman of the Board                                       (and, until 1996, Chief Executive Officer;
                                                              and, until 1995, President) of Philadelphia
                                                              Corporation for Investment Services, a
                                                              registered securities broker/dealer and
                                                              investment advisor

Michelle L. Chicoine            43     1999        1990       President and Chief Operating Officer of ENGI;
Executive Vice President                                      formerly (1998) Senior Vice President, Treasurer
                                                              and Chief Financial Officer, (1997-1998) Vice
                                                              President, Treasurer and Chief Financial Officer
                                                              and (1993-1997) Vice President and Treasurer of
                                                              ENGI

Richard B. Couser               58     1985                   Attorney with Orr & Reno, Professional Association

Joan P. Cudhea                  67     1984                   Certified Financial Planner and Registered
                                                              Investment Advisor

Sylvio L. Dupuis                65     1982                   Optometrist; President, Notre Dame College;
                                                              formerly (until 1999) Executive Director of McLane,
                                                              Graf, Raulerson & Middleton, Professional Association
                                                              law firm; formerly (until  1996) Commissioner of
                                                              Insurance - State of New Hampshire

Robert R. Giordano              61     1988        1982       Chairman and Chief Executive Officer of ENGI;
 President and Chief                                          formerly (until 1998) President and Chief Executive
 Executive Officer                                            Officer of ENGI; Chairman of ENPI; Chairman,
                                                              President and Chief Executive of ENMI

Constance B. Girard-diCarlo     52     1994                   President, Healthcare Support Services,
                                                              a division of ARAMARK Corporation, which
                                                              manages support service departments in
                                                              the healthcare industry

Andrew E. Lietz (2)             61     1998                   President, Chief Executive Officer and Director
                                                              (until 1995, Vice President and Chief Operating
                                                              Officer) of Hadco Corporation, a manufacturer of
                                                              printed circuit boards

N. George Mattaini              74     1982                   Retired President and Chief Executive Officer
 Vice Chairman of the Board                                   of the Company

John E. Tulley II               45     1997                   President and Chief Executive Officer,
                                                              Tulley Buick Pontiac Company, Inc.

</TABLE>




(1) Mr. Borer is a director of Philadelphia Corporation for Investment
    Services and Chester Valley Bancorp Inc., a NASDAQ traded company.
    Chester Valley Bancorp, Inc. is a 100% owner of Philedelphia Corporation
    for Investment Services.
(2) Mr. Leitz is a director of the Wyman-Gordon Company.




<PAGE>


<TABLE>
<CAPTION>

Executive Officers of the Registrant

The executive officers of the Registrant, except those listed as directors,
are listed below, together with position, age at December 31, 1999, 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.


                                                           Principal occupation or employment
Name and position                          Officer         during last five years other than
with the Registrant            Age          since                  with the Registrant
------------------------------------------------------------------------------------------------------
<C>                            <S>           <S>        <S>
Frank L. Childs                55            1995       Senior Vice President and Chief Financial
  Senior Vice President and                             Officer of ENGI; formerly (1998) Senior
  Chief Financial Officer                               Vice President and (1995-1997) Vice
                                                        President of ENGI

David A. Skrzysowski           53            1983       Vice President and Controller of ENGI
  Vice President and
  Controller

Stephen W. Smith               52            1997       Vice President of ENGI; formerly
  Vice President                                        (1993-1996) Director of Human Resources
                                                        of Hampshire Chemical Corporation

Scott W. Braly                 45            1999       Vice President and Chief Information
  Vice President                                        Officer of ENGI; formerly (until 1998)
                                                        Account Manager of Northeast Utilities,
                                                        a public utility holding company

Allen F. Pattee                49            1999       Treasurer of ENGI; formerly (until 1998)
  Treasurer                                             Vice President of Bell Atlantic Corporation,
                                                        a public utility holding company; formerly
                                                        (until 1997) Corporate Director of Investor
                                                        and Shareowner Relations of NYNEX Corporation,
                                                        a public utility holding company

</TABLE>


Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires
that each director and certain officers of the Company file
reports of initial beneficial ownership and changes in beneficial
ownership of the Company's common stock with the Securities and
Exchange Commission.  To the Company's knowledge, during 1999,
all directors and officers filed all such required notices except
that Mr. Margossian, a former Senior Vice President, filed a Form
5 with respect to the acquisition of 200 shares four days late.




<PAGE>




ITEM 11.  EXECUTIVE COMPENSATION

Compensation of the Directors

The Chairman of the Board of Directors receives an annual retainer of
$40,000 and the Vice Chairman receives an annual retainer of $20,000.
All other directors receive annual retainers of $10,500. Committee
chairmen receive additional annual retainers of $2,500.  Incentive
compensation in the amount of 100 shares of the Company's $1.00 par
value Common Stock is awarded to each director annually, provided
that the Company has achieved certain fiscal year earnings and
shareholder return objectives.  The Chairman and directors receive
fees of $750 for each board meeting attended and $650 for each
committee meeting attended.  The Vice Chairman and committee chairmen
receive fees of $750 for each board and committee meeting attended.
Multiple meetings of the board of directors held on the day of the
annual meeting of the board of directors are considered one meeting.
Directors who are employees receive no annual retainers, director
incentive compensation, or meeting fees.

Directors may elect to have portions of their retainers and fees
credited each year to a deferred compensation account pursuant to a
plan that provides for accrual of interest and distribution of the
deferral accounts in lump sum amounts or in equal installments over
ten years, at the option of each director, beginning on a date
designated by the director.

In fiscal 1999, each non-employee director was granted an option to
purchase 1,000 shares of the Company's Common Stock in accordance
with the 1998 Stock Option Plan.



<PAGE>




Executive Compensation

The following Summary Compensation Table shows compensation paid by
the Company for services rendered in all capacities during the fiscal
years ended September 30, 1999, 1998 and 1997 to the Chief Executive
Officer and the four other executive officers of the Company whose
salary and cash incentive and bonus award for the 1999 fiscal year
exceeded $100,000.


<TABLE>
<CAPTION>
                           SUMMARY COMPENSATION TABLE
------------------------------------------------------------------------------------------------------------------------
                                                                                           Long-term
                                                      Annual compensation                compensation
                                           --------------------------------------      ----------------      All other
                                                         Cash incentive                Restricted stock     compensation
Name and principal position     Year       Salary (1)    & bonus awards     Other         awards (2)             (3)
------------------------------------------------------------------------------------------------------------------------
<C>                             <S>          <S>            <S>            <S>            <S>                  <S>
Robert R. Giordano              1999         $266,738       $109,543 (4)    $2,864        $     -              $18,254
 President and CEO              1998          229,902         56,832         2,656         55,136 (5)           16,170
                                1997          210,797         61,217         2,234         20,403               12,132

Michelle L. Chicoine            1999         $175,000       $ 62,023 (4)    $    -        $     -              $ 7,687
 Executive Vice President       1998          126,667         34,342 (5)     1,593          8,078                7,303
                                1997          111,595         26,832         1,350          8,932                6,013

Frank L. Childs                 1999         $140,000       $ 38,417 (4)    $    -        $     -              $ 8,569
 Senior Vice President          1998          115,883         44,342 (5)         -          8,078                7,260
 and CFO                        1997          107,417         25,695             -          8,563                3,571

Kenneth M. Margossian (6)       1999         $132,123       $ 38,417 (4)    $    -        $     -              $ 7,372
 Senior Vice President          1998          115,853         29,085 (5)         -          8,023                1,499

David A. Skrzysowski            1999         $ 90,946       $ 24,014 (4)    $1,494        $     -              $ 6,063
 Vice President and             1998           87,227         16,538         1,681          5,513                5,245
 Controller                     1997           82,424         18,133         1,531          6,024                4,693



</TABLE>


(1)   Includes amounts earned and deferred without election by the
      officer and amounts deferred pursuant to Deferred Compensation
      Agreements and the Company's 401(k) plan.
(2)   There are no shares of restricted stock holdings of the above-
      named officers as of September 30, 1999.
(3)   All other compensation paid in 1999 includes: Employer
      contributions to the Company's 401(k) plan for Mr. Giordano ($5,063),
      Ms. Chicoine ($5,287), Mr. Childs ($6,213), Mr. Margossian ($5,187),
      and Mr. Skrzysowski ($4,438); value of term life insurance premiums
      paid for Mr. Giordano ($2,400), Ms. Chicoine ($2,400), Mr. Childs
      ($2,356), Mr. Margossian ($2,185), and Mr. Skrzysowski ($1,625);
      portion of interest earned in a deferred compensation account by Mr.
      Giordano in excess of 120% of federal long-term rate ($10,791).
(4)   Includes cash and stock incentive awards.
(5)   Includes an award of 1,350 shares of restricted stock that are
      subject to forfeiture and nontransferability until July 16, 2000 for
      Mr. Giordano ($36,197) and cash bonus award for Ms. Chicoine
      ($10,000), Mr. Childs ($20,000) and Mr. Margossian ($5,000) for 1998
      acquisition activities.
(6)   Mr. Margossian joined the Company on September 29, 1997 and
      resigned on November 19, 1999.




<PAGE>




Other Compensation Arrangements

Stock Options

In November 1998, the Company adopted the EnergyNorth, Inc. 1998
Stock Option Plan (Plan) to provide for grants of options to
officers, directors and key employees to purchase common stock of the
Company.  The maximum exercise period for any option is ten years.

Options granted under the Plan have been entirely incentive stock
options with the exception of options granted to directors.  The
option price per share for options granted under the Plan was
determined at 100% of the fair market value of the average closing
price for the common stock, as reported on the New York Stock
Exchange, during the ten trading days immediately preceding the date
of grant.  All options that have been granted under the Plan become
exercisable over a four-year period beginning in 1999, except for
options granted to Mr. Giordano, which become exercisable over five
years.

The following table sets forth certain information regarding stock options
granted under the Plan during the fiscal year ended September 30, 1999.


<TABLE>
<CAPTION>
                               OPTION GRANTS IN LAST FISCAL YEAR
                                       Individual Grants
-------------------------------------------------------------------------------------------------------------
                              Number of            % of options
                             securities             granted to          Exercise                       Grant
                             underlying        employees/directors       price        Expiration       date
      Name                 options granted        in fiscal year       per share         date          value
-------------------------------------------------------------------------------------------------------------
<C>                          <S>                       <S>               <S>          <S>            <S>
Robert R. Giordano           15,000                    34.1              $28.00       11/19/2008     $ 75,532
Michelle L. Chicoine         10,000                    22.7               28.00       11/19/2008       50,355
Frank L. Childs               5,000                    11.4               28.00       11/19/2008       25,177
Kenneth M. Margossian         5,000                    11.4               28.00       11/19/2008       25,177
All directors as a group      9,000                    20.4               28.00       11/19/2008      221,560

</TABLE>


The following table provides information with respect to options to
purchase shares of the Company's common stock exercised in fiscal
1999 and the value of unexercised options granted during the fiscal
year under the Plan to the named executive officers in the Summary
Compensation Table and all directors as a group and held by them as
of September 30, 1999.  The Company has no compensation plan under
which SARs are granted.




<PAGE>





                 AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
                        AND FISCAL YEAR-END OPTION VALUES

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------
                                                        Number of securities           Value of unexercised in-
                             Shares                    Underlying unexercised         the-money options at fiscal
                            Acquired                 options at fiscal year end              year end (1)
                               on        Value       ------------------------------------------------------------
       Name                 exercise    realized     Exercisable   Unexercisable      Exercisable   Unexercisable
-----------------------------------------------------------------------------------------------------------------
<C>                            <S>         <S>          <S>            <S>              <S>           <S>
Robert R. Giordano             -           -            3,571          11,429           $48,208       $154,292
Michelle L. Chicoine           -           -            2,500           7,500            33,750        101,250
Frank L. Childs                -           -            1,250           3,750            16,875         50,625
Kenneth M. Margossian          -           -            1,250           3,750            16,875         50,625
All directors as a group       -           -            2,250           6,750            30,375         91,125


</TABLE>



(1) Represents the difference between the exercise price of the
    options and the closing price of $41.50 for the Company's common
    stock as quoted by the New York Stock Exchange on September 30, 1999
    times the number of options held.

Noncontributory Retirement Plan

The following Pension Plan table sets forth estimated combined annual
benefits payable under the Company's Retirement Plan and Supplemental
Executive Retirement Plan (SERP) at age 65 to persons in specified
compensation and years of service classifications.  The combined
annual benefits shown in the table do not reflect offsets for
benefits of Social Security and for retirement benefits received from
other employers.


                               PENSION PLAN TABLE

----------------------------------------------------------------------
 Average annual earnings     15 years of    25 years of    35 years of
during highest five years      service        service        service
----------------------------------------------------------------------
       $125,000               $ 93,750       $ 93,750       $ 93,750
        150,000                112,500        112,500        112,500
        175,000                131,250        131,250        131,250
        200,000                150,000        150,000        150,000
        250,000                187,500        187,500        187,500
        300,000                225,000        225,000        225,000
        350,000                262,500        262,500        262,500
        400,000                300,000        300,000        300,000

All full-time salaried employees, including officers and certain part-
time employees, are eligible to participate in the Company's
Retirement Plan, provided an employee has reached the age of 21 and
has completed one year of service.  The SERP is a noncontributory
plan intended to supplement benefits of the Retirement Plan for
certain named executive officers, effective January 1, 1985.  Under
both plans normal retirement is at age 65 with a provision for early
retirement.  Benefits under the Retirement Plan vest after five years
of service and under the SERP vest after ten years of service.
Earnings under the plans for the executive officers named in the
Summary Compensation Table consist of regular annual compensation,
excluding bonuses or severance pay, and are the same, except for
bonuses and "Other", as the Annual Compensation and Long-Term
Compensation shown in the



<PAGE>




Summary Compensation Table.  Mr. Giordano has 34 credited years of
service under the plans, Ms. Chicoine 9 years, Mr. Childs 4 years,
Mr. Margossian 2 years and Mr. Skrzysowski 22 years.

Funding of the Retirement Plan is based on actuarial computations and
results in a pool of assets held in trust that is unallocated with
respect to any particular individual.  Benefits payable under the
Retirement Plan are calculated on the basis of straight life annuity
amounts, accrued over a 25-year period and are not subject to any
deduction for Social Security Benefits or other offset.

Benefits under the SERP are unfunded, accrue over a 15-year period
and once they are fully vested do not vary with years of service,
except that SERP participants who are included in the plan after
September 30, 1995 will have benefits reduced if they retire prior to
the normal retirement date under the Retirement Plan.  For an
individual retiring at age 65, benefits are calculated on the basis
of 75% of the average of the five highest consecutive years'
earnings, less any amounts receivable for benefits of Social
Security, the Retirement Plan, and other qualified plans of the
Company and other employers.

Employment Agreements

The Company has employment agreements with Mr. Giordano and Ms.
Chicoine under which the Company has agreed to employ Mr. Giordano
through March 31, 2003 and Ms. Chicoine for a two-year period, which
may be extended annually for an additional year.  If the Company
terminates the employment of either of these individuals other than
for breach of the agreement or misconduct, it is required to continue
salary payments including average or target incentive compensation,
deferred compensation and amounts the employee has elected to defer,
through the term of the agreement.  Such termination payments will
not be made following any termination of employment that gives rise
to payments under the management continuity agreements described
below.

Management Continuity Agreements

The Company has Management Continuity Agreements (Continuity
Agreements) with Mr. Giordano, Ms. Chicoine, Messrs. Childs,
Margossian, and Skrzysowski.  Mr. Margossian terminated his
employment, and his rights under his continuity agreement terminated
on November 19, 1999.  The Continuity Agreements provide that in the
event of termination of employment or a reduction in compensation,
position or other conditions of employment within a specified period
following a Change in Control of the Company, as defined in the
Continuity Agreements, or termination by the employee for Good
Reason, as defined in the Continuity Agreements, following a Change
in Control, the Company shall pay to the employee a lump-sum
severance benefit and certain other benefits.  The severance benefit
payable to Mr. Giordano and Ms. Chicoine is three times his or her
annual salary and incentive and deferred compensation, a prorated
incentive payment for the year in which termination occurs,
continuation of benefits or a payment equal to the present value of
those benefits and, for Mr. Giordano, the present value of the
additional amount he would have received under the Retirement Plan
and the SERP if he had continued to be employed for three years from
termination.  In addition, the Company is required to make additional
payments to Mr. Giordano and Ms. Chicoine sufficient on an after-tax
basis to satisfy any tax liability incurred under the "parachute" tax
rules of the Internal Revenue Code. The severance benefit payable to
Mr. Childs is 2.95 times his annual salary




<PAGE>




and incentive and deferred compensation.  The severance benefit payable
to Mr. Skrzysowski is the greater of two times his annual salary or 2.75
times his five-year average taxable compensation.  In each continuity
agreement, except for Mr. Giordano's and Ms. Chicoine's, no severance
benefits are paid to the extent that such benefits, aggregated with other
benefits paid to the employee, constitute "excess parachute payments"
within the meaning of Section 280G of the Internal Revenue Code.


ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
           MANAGEMENT

The following table sets forth information regarding beneficial
ownership of the Company's $1.00 par value Common Stock, its only
class of securities, by each director and certain executive officers
(Messrs. Childs, Margossian and Skrzysowski), and all directors and
executive officers as a group, as of October 8, 1999.  No person is
known to the Company to own more than 5% of the Company's stock.

                             PRINCIPAL STOCKHOLDERS

--------------------------------------------------------------------------------
                                          Number of shares         Percentage of
Name of individual                     beneficially owned (6)      common stock
--------------------------------------------------------------------------------
Roger C. Avery (1)                             34,727                  1.046
Edward T. Borer (2)                            15,539                    *
Michelle L. Chicoine                            5,371                    *
Frank L. Childs                                 2,592                    *
Richard B. Couser                                 656                    *
Joan P. Cudhea (3)                             14,302                    *
Sylvio L. Dupuis                                1,295                    *
Robert R. Giordano (4)                         21,267                    *
Constance B. Girard-diCarlo                       597                    *
Andrew E. Lietz                                 1,352                    *
Kenneth M. Margossian                           1,551                    *
N. George Mattaini (5)                         11,812                    *
David A. Skrzysowski                            1,720                    *
John E. Tulley II                                 800                    *
All directors and executive officers as a
 group (14 in number at October 8, 1999)      113,581                  3.421
_______________
*  Less than 1%.

(1)  Includes 12,879 shares held by Mr. Avery solely in a fiduciary
     capacity and in which he disclaims beneficial ownership.
(2)  Includes 963 shares held by Mr. Borer's spouse, in which he
     disclaims beneficial ownership.
(3)  Includes 1,690 shares held by Ms. Cudhea's daughter-in-law, in
     which she disclaims beneficial ownership and over which she shares
     investment power only.
(4)  Includes 430 shares held by Mr. Giordano's spouse, in which he
     disclaims beneficial ownership.
(5)  Includes 7,404 shares held by Mr. Mattaini's spouse, in which
     he disclaims beneficial ownership.
(6)  Beneficial ownership includes shares that the following persons
     have a right to acquire upon exercise of options:  Mr. Giordano,
     3,571; Ms. Chicoine, 2,500; Mr. Childs, 1,250; Mr. Margossian, 1,250;
     and each director who is not also an employee, 250.




<PAGE>




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

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

  (1) Financial Statements

    The following financial statements are included herein under Part II,
    Item 8:
                                                                    Page No(s).
                                                                  in this Report
                                                                  --------------
      Consolidated Statements of Income for the years ended
        September 30, 1999, 1998 and 1997                               21
      Consolidated Balance Sheets at September 30, 1999 and 1998        22
      Consolidated Statements of Capitalization at September 30,
        1999 and 1998                                                   23
      Consolidated Statements of Common Stockholders' Equity
        for the years ended September 30, 1999, 1998 and 1997           24
      Consolidated Statements of Cash Flows for the years ended
        September 30, 1999, 1998 and 1997                               25
      Notes to Consolidated Financial Statements                      26-41
      Report of Independent Public Accountants                          42

  (2) Financial Statement Schedules

      The following supplementary financial statement schedules
      required by Rule 5-04 of Regulation S-X, and report thereon, are
      filed as part of this Form 10-K on the page indicated below:


      Schedule                                                       Page No.
       Number                    Description                      in this Report
      --------                   -----------                      --------------

         II   Consolidated Valuation and Qualifying Accounts for the
              three years ended September 30, 1999                      54

         Report of Independent Public Accountants                       42




<PAGE>




     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 56 through 59.

(b) Reports on Form 8-K

      A current report on Form 8-K reporting the occurrence of
      an event covered by Item 5 was filed on July 20, 1999 by
      the Company regarding the Company's plan to merge with
      Eastern Enterprises.

(c) Exhibits - See Exhibit Index on pages 56 through 59.

(d) Financial Statement Schedules





<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                     Balance
   Year ended                           beginning    costs and     to other                    at end
September 30,       Description         of period     expenses    accounts(1)  Deductions     of period
-------------------------------------------------------------------------------------------------------
         <C>     <S>                     <S>          <S>            <S>         <S>           <S>
         1999    Allowance for
                  doubtful accounts      $1,127       $  916         $179        $1,107        $1,115
         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

__________________
(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 17, 1999     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 17, 1999.

/s/ Robert R. Giordano                Director, President and
------------------------              Chief Executive Officer
Robert R. Giordano                    (principal executive officer)

/s/ Frank L. Childs                   Senior Vice President and
------------------------              Chief Financial Officer
Frank L. Childs                       (principal financial officer)

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

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

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

/s/ Michelle L. Chicoine              Director
------------------------
Michelle L. Chicoine

/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
-------                    -----------

 2.0     Agreement and Plan of Reorganization dated July 14, 1999
         among Eastern Enterprises, EE Acquisition Company, and
         EnergyNorth, Inc.  Schedules described in the Agreement
         will be furnished supplementally to the SEC upon request.

 2.1     Amendment No. 1 to Agreement and Plan of Reorganization,
         dated November 4, 1999.

 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.




<PAGE>




 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 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.

 4.8     Amendment to Rights Agreement (undated - 1999).

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     Contract Restructuring Letter Agreement between Tennessee Gas
         Pipeline Company and EnergyNorth Natural Gas, Inc. effective
         November 1, 1999.

10.4     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.

10.5     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.

10.6     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.




<PAGE>




10.7     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.

10.8     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.

10.9     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.

10.10    Amended and Restated Employment Agreement, dated as of
         July 14, 1999, between Robert R. Giordano and the Registrant.

10.11    Amended and Restated Employment Agreement, dated as of
         July 14, 1999, between Michelle L. Chicoine and the Registrant.

10.12    Amended and Restated Management Continuity Agreement, dated as
         of July 14, 1999, between Robert R. Giordano and the Registrant.

10.13    Amended and Restated Management Continuity Agreement, dated as
         of July 14, 1999, between Michelle L. Chicoine and the Registrant.

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 12, 1995,
         between David A. Skrzysowski and the Registrant.

10.16    Consulting Agreement, dated as of July 1999, among EnergyNorth,
         Inc., Eastern Enterprises, and Robert R. Giordano.

10.17    Employment and Related Matters Agreement, dated July 14, 1999,
         between Eastern Enterprises and Robert R. Giordano.

10.18    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.





<PAGE>




10.19    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.

10.20    EnergyNorth, Inc. 1998 Stock Option Plan is incorporated by reference
         to Exhibit 10.18 to EnergyNorth, Inc.'s Annual Report on Form 10-K
         (File No. 1-11441) for the year ended September 30, 1998.

21       Subsidiaries of the Registrant is incorporated by  reference to
         Exhibit 21 to EnergyNorth, Inc.'s Annual Report on Form 10-K
         (File No. 1-11441) for the year ended September 30, 1998.

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.