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 000-25305
ENERGYNORTH NATURAL GAS, INC.
(Exact name of registrant as specified in its charter)
New Hampshire 02-0209312
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1260 Elm Street, P.O. Box 329, Manchester, New Hampshire 03105-0329
(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: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months, and (2) has been subject to
such filing requirements for the past 90 days. Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [ X ]
At December 2, 1999, nonaffiliates held no shares of the registrant's
$25.00 par value common stock, all of which was held by EnergyNorth, Inc.
At the close of business on December 2, 1999, the registrant had 120,000
shares outstanding of its $25.00 par value common stock.
ENERGYNORTH NATURAL GAS, INC. MEETS THE CONDITIONS SET FORTH IN GENERAL
INSTRUCTION I(1)(a) and (b) OF FORM 10-K AND THIS REPORT THEREFORE OMITS
CERTAIN INFORMATION.
Page 1 of 41 pages.
Exhibit Index appears on Pages 40 and 41.
<PAGE>
<TABLE>
TABLE OF CONTENTS
<S> <C> <C>
Part I Page No(s).
------------
Item 1. Business
General 3-4
Gas Distribution Business 4-5
Summary of Revenues 5
Deregulation 6
Competition 6
Gas Supply
General 7
Supply, Pipeline Transportation and Underground Storage Contracts 7-8
Cost of Purchased and Produced Gas 8
Supervision and Regulation 8
Employees 9
Item 2. Properties 9
Item 3. Legal Proceedings 9-11
Item 4. Submission of Matters to a Vote of Security Holders 11
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 11
Item 6. Selected Financial Data 11
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 12-17
Item 7A. Quantitative and Qualitative Disclosures about Market Risk 17
Item 8. Financial Statements and Supplementary Data 18-35
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 35
Part III
Item 10. Directors and Executive Officers of the Registrant 35
Item 11. Executive Compensation 35
Item 12. Security Ownership of Certain Beneficial Owners and Management 35
Item 13. Certain Relationships and Related Transactions 35
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 36-38
Signatures 39
Exhibit Index 40-41
</TABLE>
<PAGE>
ENERGYNORTH NATURAL GAS, INC.
FORM 10-K
PART I
ITEM 1. BUSINESS
General
The business of EnergyNorth Natural Gas, Inc. (Company),
incorporated in the state of New Hampshire in 1945, is the
purchase, transportation and sale of natural gas for residential,
commercial and industrial use in New Hampshire. The Company is a
wholly owned subsidiary of EnergyNorth, Inc. (ENI), a public
utility holding company, also incorporated in the state of New
Hampshire. Both the Company and ENI are headquartered at 1260 Elm
Street, Manchester, New Hampshire.
In general, the senior management of ENI serves as the senior
management of the Company. ENI provides for administrative
support and services and establishes policies, plans and goals.
On July 14, 1999, ENI and Eastern Enterprises (Eastern), a
Massachusetts business trust, entered into an Agreement and Plan
of Reorganization (Agreement) which provides for the merger of
ENI with a subsidiary of Eastern, as a result of which ENI'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, ENI and Eastern
amended the Agreement. Under the amended Agreement, holders of
outstanding shares of ENI'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, ENI and Eastern would
nonetheless merge, and holders of outstanding shares of ENI'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 ENI'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 service territory of the Company 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,
the Company 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. The company's service territory offers a favorable
business climate with no general sales or personal
<PAGE>
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.
The Company'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, the Company expanded into Berlin, New
Hampshire and began providing natural gas service in early fiscal
year 2000. The Company 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, the company has an
opportunity for growth in the retail sales market. During the
past four years, the Company 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 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.
Gas Distribution Business
The Company distributes natural gas as a regulated utility
pursuant to franchise authority granted by the Commission. No
operations are outside New Hampshire. While the Company'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
<PAGE>
approximately 88% were residential and 12% were commercial and
industrial. During fiscal 1999, no customer purchased more than
2.5% of the total annual sales and transportation volume.
The Company 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 the Company's interstate pipeline take
stations. The customer contracts with the Company to transport
the gas from the take station to its facility. To ensure a
continual, uninterrupted supply, the Company also provides an
optional, separate standby service as a backup to the gas
supplies of transportation customers. As of September 30, 1999,
the Company had 89 firm transportation customers.
The Company distributes gas to its 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. The Company serves more than 75% of New
Hampshire's natural gas customers.
On September 7, 1999, the Commission approved a petition filed by
the Company 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, the Company
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. The
company anticipates additional development in the vicinity of the
prison complex, as well as interest from other energy users in
the city of Berlin.
Summary of Revenues
Revenues attributable to various categories of gas distribution
and related operations during the last three fiscal years are as
follows (in thousands, unaudited):
September 30,
-------------------------------
1999 1998 1997
-------------------------------
Sales service $72,891 $82,686 $91,670
Transportation service 3,726 2,610 1,308
Service and appliance sales 1,984 1,910 1,949
Rentals 623 686 750
-------------------------------
$79,224 $87,892 $95,677
===============================
During the winter period, November 1 through March 31, the
Company's gas revenues are substantially higher than during the
summer months. The increase in gas revenues during the winter,
and the concomitant increase in gas supply requirements, occurs
because approximately 90% of the Company's customers use natural
gas for heating.
<PAGE>
Deregulation
The Company 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 the Company'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, the Company 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 the Company's total gas delivered. The Company
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 commercial and industrial customers, as
well as to consider unbundling service to residential 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. The Company cannot predict the outcome
of the proceeding, or the impact on transportation volumes or
customers.
The Company is the sole distributor and transporter of natural
gas in its franchise area. The Tennessee Gas Pipeline Company
(Tennessee) serves all of the Company'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 the Company'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 the Company's
commercial and industrial customers, some of whom have the
capability to use alternative fuels. The Company 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. The
Company continues to add customers who might otherwise elect to
use oil, because energy decisions are also based on factors other
than cost, such as service, cleanliness and environmental impact.
Demand for natural gas is expected to continue to increase as
national attention remains focused on its environmental
advantages, efficiency and security of supply. Commercial and
industrial customers continue to find gas technologies and
equipment attractive as they deal with the requirements of the
Clean Air Act Amendments of 1990 and other federal environmental
legislation.
<PAGE>
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. The Company's gas supply is principally natural gas,
transported on interstate pipelines. The primary pipeline the
Company uses to bring natural gas to its distribution territory
is the Tennessee Gas Pipeline (TGP). The Company contracts for
56,833 Dekatherms (Dth) of primary firm and 8,000 Dth of
interruptible capacity on TGP. The Company 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).
The Company's natural gas supply contracts are a mix of long and
short-term agreements. The Company'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 the Company's natural gas supply portfolio was firm delivered
winter supplemental supply. One percent of the Company's annual
supply in fiscal year 1999 was purchased in the spot market.
In fiscal year 1999, approximately 61% of the gas delivered by
the Company came from domestic pipeline sources, 24% from
Canadian pipeline sources, and 14% from supplemental pipeline
sources. Liquefied petroleum gas (LPG) and liquefied natural gas
(LNG) purchases from both domestic and foreign sources made up
approximately 1% of the gas delivered by the Company. LPG and
LNG are vaporized at the Company'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 the
Company's system during fiscal year 1999.
All pipeline volumes to the Company'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 the Company 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.
The Company has underground storage agreements with four storage
field operators in the Pennsylvania-New York area. The Company
fills these storage fields each summer for use during the
following winter. Total combined storage controlled by the
Company equals 2,579,431 Dth with daily withdrawal rights of
30,833 Dth. All underground storage fields operate under FERC
approved tariffs. The Company also owns on-site storage
facilities capable of holding 115,660 Dth of LPG and 13,057 Dth
of LNG. The Company 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).
<PAGE>
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 dollar-for-dollar recovery of gas costs
(including pipeline, storage, LPG and LNG). The Company 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.
The Company has a Natural Gas Price Risk Management Program
designed to protect customers from sharp increases in the
commodity cost of gas. Under the program, the Company 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
The Company is subject to regulation by the Commission, which has
authority over accounting, rates and charges, the issuance of
securities and certain operating matters. Changes in utility
rates and charges cannot be made without a 30-day notice to the
Commission, which has the power to suspend, investigate and
change any proposed increase in rates and charges.
The gas distribution business of the Company is subject to
extensive safety regulations and reporting requirements
promulgated by the United States Department of Transportation,
but is not otherwise subject to direct regulation by federal
agencies except as to environmental matters. The Company is also
subject to zoning and other regulations by local authorities.
Its capital expenditures, earnings and operations have not been
materially affected by environmental and local regulation.
<PAGE>
Employees
At September 30, 1999, the Company had 102 full-time employees,
represented by two contracts with Local 12012 of the United
Steelworkers of America. The contracts expire in 2001. A
substantial portion of the cost of ENI's 115 full-time employees
is allocated to the Company. None of ENI's employees are
represented by labor unions.
ITEM 2. PROPERTIES
The Company's gas distribution facilities constitute the majority
of its physical assets. As of September 30, 1999, the Company
had approximately 1,113 miles of mains and 702 miles of service
connections. The 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 and are subject to the liens of the indentures
securing the Company's First Mortgage Bonds. In some cases,
motor vehicles are subject to purchase money security interests
held by banks. The Company also has long-term leases for
computer equipment and vehicles.
ITEM 3. LEGAL PROCEEDINGS
In addition to the matters described below, the Company is a
party in several proceedings of the sort that arise in the
ordinary course of its business. Such actions, for the most
part, are covered by insurance and, to the extent that they are
not fully covered, the damages sought are not material in amount.
The Company is a party to various routine Commission proceedings
relating to operations, none of which is expected to have a
material impact on the Company's earnings or assets.
The Company, and certain of its predecessors, 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.
<PAGE>
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.
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.
<PAGE>
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
OMITTED
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
(a) No equity securities of the Company were sold by it during
the period covered by this report. All 120,000 shares of the
Company's outstanding common stock are held by ENI.
ITEM 6. SELECTED FINANCIAL DATA
OMITTED
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Earnings
Net income in 1999 was $3.8 million compared to $4.9 million in
1998. Impacting 1999 financial results were reorganization costs
of $1.1 million 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 margin by approximately $1.2 million,
after taxes. In 1998, margin was reduced approximately $1.7
million, 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.
Sales and Revenues
The rates charged to customers are regulated by the Commission.
The Commission is required by New Hampshire law to allow the
Company to charge rates that are just and reasonable, such that
the Company is compensated for the cost of providing service and
allowed a reasonable rate of return on its investment. The
Company regularly assesses whether it is earning a reasonable
return and files for rate increases when it determines that it is
not being permitted to earn a reasonable return.
The Company generates revenues primarily through the sale and
transportation of natural gas. The Company's gas sales are
divided into two categories: firm, whereby the Company must
supply gas to customers on demand; and interruptible, whereby the
Company may, generally during colder months, temporarily
discontinue service to high-volume commercial and industrial
customers. Sales of gas to interruptible customers do not
materially affect the Company's operating income because all
margin on such sales is returned to firm customers.
The Company'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.
The Company's sales are responsive to colder weather because the
majority of firm customers use natural gas for space heating
purposes. The Company measures weather through the use of degree
days. A degree day is calculated by subtracting the average
temperature for the day from 65 degrees Fahrenheit. The "normal"
number of degree days during any period is calculated based upon
a rolling approximate 30-year average number of degree days
during such period. The table below discloses degree day data as
recorded at the U.S. weather station in Concord, New Hampshire,
comparing actual degree days to the previous period and to
normal. Because of the size and topographical variations of the
Company's service territory, weather conditions within such
<PAGE>
territory often vary. The Company considers Concord, New
Hampshire weather data to be representative of weather conditions
within its service territory.
<TABLE>
<CAPTION>
Degree days
-------------------------
Prior Change vs. Change vs.
Actual period Normal prior period normal
-----------------------------------------------------
<S> <C> <C> <C> <C> <C>
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 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.
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.
Operating Expenses
Operations and maintenance expense for fiscal year 1999 was
essentially unchanged from the prior year. The warmer winter
season resulted in lower maintenance and bad debt expenses. Other
operating and administrative costs decreased as a result of
effective cost containment efforts, which offset increases in
labor costs and health insurance and other employee benefit
costs.
Depreciation and amortization expense increased 17.5% in 1999 and
reflects normal upgrades to the distribution system and related
facilities and increases in amortization of environmental
remediation costs. Net additions to property, plant and
equipment were $12.1 million and $13.2 million in 1999 and 1998,
respectively.
Taxes other than income taxes decreased almost 3% as a result of
favorable property tax rates.
Reorganization costs are not currently tax deductible. The lower
level of pretax income is the main reason for the decrease in
federal and state income taxes in 1999.
<PAGE>
Capital Resources and Liquidity
Because of the seasonal nature of the Company's 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 $12.1 million, dividend payments of $3.8 million
and environmental remediation of $4.9 million. 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
$14.2 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.
Capital expenditures for fiscal year 2000 are currently projected
at approximately $12 million. Additional cash requirements will
be necessary for the payment of dividends, environmental
remediation, annual sinking fund requirements and maturities of
long-term debt and working capital. Cash to fund these
requirements is expected to be provided principally by internally
generated funds and short-term bank borrowings under the
Company's lines of credit. At September 30, 1999, the Company
had available lines of credit aggregating $15 million, $14.2
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 44% common equity and 56% 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 9 to the financial statements.
<PAGE>
Results of Operations 1998 Compared to 1997
Net income declined to $4.9 million in 1998 from 1997 net income
of $6 million. The 1998 decrease in earnings was due primarily
to the impact of warmer weather in the Company's service
territory. In addition, 1997 earnings were $649,000 higher as a
result of a favorable net property tax settlement.
Operating revenues were $85.3 million in 1998 compared to $93
million in 1997, an 8.3% decrease. Firm sales gas revenues in
1998 were $78.8 million compared to $85.7 million in 1997. Firm
transportation revenues of $2.4 million were twice the level
achieved in 1997. Lower cost of gas rates was the primary reason
for lower operating revenues in 1998. The average unit cost of
gas sold in 1998 was $4.09 per Mcf compared to $4.28 per Mcf in
1997. The weather in 1998 was 12.9% warmer that normal and 11.4%
warmer than the previous year. Growth in the average number of
customers of 2.4% in 1998 helped mitigate the effects of the
warmer temperatures. Firm sendout, including transportation, was
11.6 Bcf compared to 11.5 Bcf in 1997. Volumes transported
increased more than 121%. This increase included a shift of
207,000 Mcf from firm commercial and industrial sales to
transportation, representing a decrease of $900,000 in operating
revenues attributable to the commodity cost of gas.
Operations and maintenance expense was approximately the same as
the prior year. Reductions in the work force, other cost saving
initiatives and workers' compensation and health insurance
refunds helped offset most of the increases from liability
insurance, uncollectible accounts and other administrative
expenses.
Taxes other than income taxes increased more that $1.1 million
due primarily to a favorable property tax settlement, net of
adjustments, of more than $1 million recorded in 1997.
New Accounting Standards and Pronouncements
During fiscal year 1999, the Company implemented two 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. 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.
Neither 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
<PAGE>
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.
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
<PAGE>
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>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(a) Financial Statements required by Regulation S-X
Statements of Income EnergyNorth Natural Gas, Inc.
(In thousands)
For the years ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------
Operating revenues:
Utility gas service $75,729 $84,274 $91,965
Other 888 1,022 1,013
-------------------------------
Total operating revenues 76,617 85,296 92,978
-------------------------------
Operating expenses:
Cost of gas sold 36,636 46,693 54,633
Operations and maintenance 18,645 18,445 18,397
Depreciation and amortization 6,322 5,381 4,969
Taxes other than income taxes 3,634 3,738 2,590
Federal and state income taxes 2,740 2,812 3,478
-------------------------------
Total operating expenses 67,977 77,069 84,067
-------------------------------
Operating income 8,640 8,227 8,911
Other income, net 849 1,111 792
Reorganization cost 1,053 - -
Interest expense:
Interest on long-term debt 3,584 3,628 2,657
Other interest 1,021 797 1,061
-------------------------------
Total interest expense 4,605 4,425 3,718
-------------------------------
Net income $ 3,831 $ 4,913 $ 5,985
===============================
The accompanying notes are an integral part of these financial statements.
<PAGE>
<TABLE>
<CAPTION>
Balance Sheets EnergyNorth Natural Gas, Inc.
(In thousands)
September 30, 1999 1998
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C>
Assets
Property:
Utility plant, at cost $169,856 $158,564
Accumulated depreciation and amortization 56,126 51,309
----------------------
Net utility plant 113,730 107,255
----------------------
Current assets:
Cash and temporary cash investments 1,862 1,756
Accounts receivable (net of allowances of $1,069 in 1999 and $1,088 in 1998) 1,109 1,828
Unbilled revenues 559 516
Deferred gas costs 1,524 -
Materials and supplies 1,505 1,411
Supplemental gas supplies 9,483 9,479
Prepaid and deferred taxes 2,415 1,766
Recoverable FERC 636 transition costs - 252
Prepaid expenses and other 2,259 2,028
----------------------
Total current assets 20,716 19,036
----------------------
Deferred charges and other assets:
Regulatory asset - income taxes 2,465 2,401
Recoverable environmental costs 11,646 6,113
Other deferred charges and assets 2,200 1,970
----------------------
Total deferred charges and other assets 16,311 10,484
----------------------
Total assets $150,757 $136,775
======================
Stockholder's equity and liabilities
Capitalization (see accompanying statements) $ 86,807 $ 87,235
----------------------
Current liabilities:
Notes payable to banks 14,178 1,891
Current portion of long-term debt 412 450
Inventory purchase obligation 8,329 8,712
Accounts payable 4,973 4,670
Accounts payable to affiliates 4,227 2,145
Deferred gas costs - 3,841
Accrued interest 245 257
Accrued and deferred taxes 525 524
Accrued FERC 636 transition costs - 252
Accrued environmental remediation costs 4,132 2,345
Customer deposits and other 874 1,313
----------------------
Total current liabilities 37,895 26,400
----------------------
Commitments and contingencies
Deferred credits:
Deferred income taxes 20,326 17,930
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 2,515 2,459
----------------------
Total deferred credits 26,055 23,140
----------------------
Total stockholder's equity and liabilities $150,757 $136,775
======================
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Statements of Capitalization EnergyNorth Natural Gas, Inc.
(In thousands, except share information)
September 30, 1999 1998
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Capitalization:
Common stockholder's equity:
Common stock - par value of $25 per share;
120,000 shares authorized, issued and outstanding $ 3,000 $ 3,000
Amount in excess of par value 22,538 22,538
Retained earnings 19,276 19,265
-------------------
Total common stockholder's equity 44,814 44,803
-------------------
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
Notes payable
Due through 2001 prime plus .50% 117 240
-------------------
42,405 42,882
Less current portion 412 450
-------------------
Total long-term debt 41,993 42,432
-------------------
Total capitalization $86,807 $87,235
===================
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Statements of Retained Earnings EnergyNorth Natural Gas, Inc.
(In thousands)
For the years ended September 30, 1999 1998 1997
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at beginning of year $19,265 $18,155 $15,819
Add - net income 3,831 4,913 5,985
---------------------------------
23,096 23,068 21,804
Deduct - cash dividends on common stock 3,820 3,803 3,649
---------------------------------
Balance at end of year $19,276 $19,265 $18,155
=================================
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Statements of Cash Flows EnergyNorth Natural Gas, Inc.
(In thousands)
For the years ended September 30, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $ 3,831 $ 4,913 $ 5,985
Noncash items:
Depreciation and amortization 6,877 5,837 5,411
Deferred taxes and investment tax credits, net 2,095 292 1,526
Changes in:
Accounts receivable, net 719 1,169 (1,166)
Unbilled revenues (43) 86 (20)
Inventories (98) (311) (301)
Prepaid expenses and other (231) (22) (165)
Deferred gas costs (5,365) 2,542 5,083
Accounts payable 303 (662) 46
Accounts payable to affiliates, net 2,082 (288) 1,844
Accrued liabilities 11 (24) (512)
Accrued/prepaid taxes (649) (143) (1,153)
Payments for environmental costs and other (4,547) 257 (3,214)
-------------------------------------
Net cash provided by operating activities 4,985 13,646 13,364
-------------------------------------
Cash flows from investing activities:
Additions to property (12,081) (13,152) (11,977)
-------------------------------------
Cash flows from financing activities:
Cash dividends on common stock (3,820) (3,803) (3,649)
Issuance of long-term debt - - 22,217
Repayment of long-term debt (477) (515) (7,568)
Repayment of capital lease obligation - - (25)
Change in notes payable to banks 12,287 1,891 (9,535)
Change in inventory purchase obligation (383) 860 (15)
Change in other financing activities (405) 76 (370)
-------------------------------------
Net cash provided by (used for) financing activities 7,202 (1,491) 1,055
-------------------------------------
Net increase (decrease) in cash and temporary cash investments 106 (997) 2,442
Cash and temporary cash investments, beginning of year 1,756 2,753 311
-------------------------------------
Cash and temporary cash investments, end of year $ 1,862 $ 1,756 $ 2,753
=====================================
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
ENERGYNORTH NATURAL GAS, INC.
Notes to Financial Statements
Note 1. Accounting Policies
The significant accounting policies followed by EnergyNorth
Natural Gas, Inc. (Company) are set forth below.
Business Organization
- ---------------------
The Company is a wholly owned subsidiary of EnergyNorth, Inc.
Transactions between the Company and other affiliated companies
include payments for management, accounting, data processing and
other services. The Company is a regulated gas distribution
utility primarily located in southern and central New Hampshire
and also provides service and sells appliances. 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."
Revenue Recognition
- -------------------
Revenues derived from the sale and transportation of natural gas
are based on rates authorized by the Commission. Customers'
meters are read and bills are rendered on a cycle basis
throughout the month. The Company records unbilled revenues
related to gas delivered but not billed at the end of the ac
counting period.
Cost of Gas Rates
- -----------------
The Company's tariff includes a cost of gas rate that permits
billings 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 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. Under depreciation practices required
by the Commission, when gas utility assets under the composite
<PAGE>
method are retired from service, the cost of the retired assets
is removed from the property accounts and charged, together with
any cost of removal, to the accumulated depreciation accounts.
For all other assets, when assets are sold or retired, the cost
of the assets and their related accumulated depreciation are
removed from the respective accounts, net removal costs are
recorded and any gain or loss is included in income.
Deferred Charges
- ----------------
Total deferred charges consist primarily of regulatory assets and
the cost of issuing debt. The Company has established various
regulatory assets in cases where the Commission has permitted, or
is expected to permit, recovery of specific costs over a period
of time. At September 30, 1999, regulatory assets included $11.6
million for environmental investigation and remediation costs and
$2.5 million of unrecovered deferred state income taxes (see Note6).
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 balance sheet by 3%. In the
event of refinancing, there would be no gain or loss as, under
established regulatory procedure, any such difference would be
reflected in rates and have no effect on income.
Derivative Instruments and Hedging Activities
- ---------------------------------------------
The Company utilizes call and put options 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
<PAGE>
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 gains, net $(16)
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) $4,330 $3,957 $3,821
Income taxes 1,119 2,761 3,557
In preparing the accompanying statements of cash flows, all
highly liquid investments having maturities of three months or
less when acquired were considered to be cash equivalents and
classified as cash and temporary cash investments.
<PAGE>
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 balance sheets. Inventory
purchase obligations under this financing agreement are reflected
as a current liability in the accompanying balance sheets.
Note 4. Notes Payable to Banks
As of September 30, 1999, the Company had $15 million available
under various unsecured bank lines of credit that are renewed
annually, $14.2 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.
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 $412
2001 371
2002 333
2003 333
2004 333
<PAGE>
Note 6. Income Taxes
The Company files a consolidated federal income tax return with
its parent company. For financial reporting and rate purposes,
the Company provides taxes on a separate return basis.
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 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 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 414 419
Deferred compensation 343 262
Other 433 864
--------------------
Total deferred tax assets 2,490 4,299
--------------------
Deferred tax liabilities:
Property-related 18,116 17,073
Environmental costs 2,645 1,455
Other 2,047 1,972
--------------------
Total deferred tax liabilities 22,808 20,500
--------------------
Net deferred tax liability $20,318 $16,201
====================
<PAGE>
Deferred income taxes were classified in the accompanying balance sheets at
September 30, 1999 and 1998 as follows (in thousands):
1999 1998
- -----------------------------------------------------------------------------
Current $ (8) $(1,729)
Long-term 20,326 17,930
--------------------
Total $20,318 $16,201
====================
The components of federal and state income taxes reflected in the accompanying
statements of income for the years ended September 30, 1999, 1998 and 1997 were
as follows (in thousands):
1999 1998 1997
- -----------------------------------------------------------------------------
Federal:
Current $ (630) $2,702 $3,369
Deferred 2,996 (268) (378)
Investment tax credits (123) (124) (136)
--------------------------------
Total federal 2,243 2,310 2,855
--------------------------------
State:
Current (276) 555 701
Deferred 773 (53) (78)
--------------------------------
Total state 497 502 623
--------------------------------
Total provision for income taxes $2,740 $2,812 $3,478
================================
The total federal and state income tax provision, as a percentage of income
before federal and state income taxes, was 41.7%, 36.4% and 36.7% 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>
<CAPTION>
1999 1998 1997
- --------------------------------------------------------------------------------------
<S> <C> <C> <C>
Tax calculated at statutory rate $2,234 $2,627 $3,217
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 328 331 411
Other, net 329 6 14
-----------------------------
Total provision for income taxes $2,740 $2,812 $3,478
=============================
</TABLE>
<PAGE>
Note 7. 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 is also charged for pension expense for the
management pension plan of the parent company.
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.
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 $173,000, $230,000 and $216,000, respectively.
The Company has funded these benefit costs by making cash
contributions, at the same level of expense recorded, to a
voluntary employee benefit association (VEBA) trust.
<TABLE>
<CAPTION>
(In thousands) Pension Medical and life
-------------------------------------------
For the years ended September 30, 1999 1998 1999 1998
- --------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <S>
Change in benefit obligation:
Benefit obligation at beginning of year $8,425 $7,336 $2,439 $2,522
Service cost 274 245 52 49
Interest cost 576 537 167 186
Participant contributions - - - -
Plan amendments - - - -
Benefits paid (452) (388) (146) (117)
Actuarial (gain) or loss (595) 695 (59) (201)
-------------------------------------------
Benefit obligation at end of year $8,228 $8,425 $2,453 $2,439
===========================================
Change in plan assets:
Fair value of plan assets at beginning of year $9,167 $9,135 $1,248 $1,064
Actual return on plan assets 898 201 80 76
Employer contributions 222 218 187 226
Participant contributions - - - -
Benefits paid (452) (387) (146) (118)
-------------------------------------------
Fair value of plan assets at end of year $9,835 $9,167 $1,369 $1,248
===========================================
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
(In thousands) Pension Medical and life
-------------------------------------------
For the years ended September 30, 1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <S>
Reconciliation of funded status:
Funded status $1,607 $ 741 $(1,084) $(1,191)
Contributions between 7/31 and 9/30 - - 43 57
Unrecognized actuarial (gain) or loss (294) 372 (919) (966)
Unrecognized transition (asset) of obligation (205) (265) 1,961 2,101
Unrecognized prior service cost 183 239 - -
-------------------------------------------
Net amount recognized at year end $1,291 $1,087 $ 1 $ 1
===========================================
Additional year-end information for plans
with benefit obligations in excess of plan
assets:
Benefit obligation $ - $ - $ 2,453 $ 2,439
Fair value of plan assets - - 1,369 1,248
Components of net periodic benefit cost:
Service cost $ 274 $ 245 $ 52 $ 50
Interest cost 576 537 167 186
Expected return on plan assets (827) (729) (124) (102)
Amortization of prior service cost 56 56 - -
Amortization of transitional (asset) or obligation (60) (60) 140 140
Recognized actuarial (gain) or loss - - (62) (44)
-------------------------------------------
Net period benefit cost $ 19 $ 49 $ 173 $ 230
===========================================
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 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.
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 compnents $ 9,743 $ (9,032)
Postretirement benefit obligation 100,603 (93,820)
<PAGE>
The Company has employee 401(k) savings and investment plans
covering substantially all employees. The Company made
contributions of $76,000, $87,000 and $85,000 for the years ended
September 30, 1999, 1998 and 1997, respectively.
Note 8. 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 $89
2001 51
2002 28
2003 9
2004 9
The total rental expense charged to operations for the years
ended September 30, 1999, 1998 and 1997 was approximately
$735,000, $807,000 and $947,000, respectively.
Note 9. Commitments and Contingencies
Contracts
- ---------
The Company has various contractual agreements covering the
transportation of natural gas, underground storage facilities and
the purchase of natural gas, which are recoverable under the
Company's cost of gas rates. These contracts expire at various
times from 1999 to 2011.
Litigation
- ----------
The Company has 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
<PAGE>
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. 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.
Note 10. Merger
On July 14, 1999, ENI and Eastern Enterprises (Eastern), a
Massachusetts business trust, entered into an Agreement and Plan
of Reorganization (Agreement) which provides for the merger of
ENI with a subsidiary of Eastern, as a result of which ENI'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, ENI and Eastern
amended the Agreement. Under the amended Agreement, holders of
outstanding shares of ENI'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, ENI and Eastern would
nonetheless merge, and holders of outstanding shares of ENI'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 ENI'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. Reorganization costs incurred by the Company as a
result of the impending merger were $1.1 million in 1999.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
EnergyNorth Natural Gas, Inc.:
We have audited the accompanying balance sheets and statements of
capitalization of EnergyNorth Natural Gas, Inc. (a New Hampshire
corporation and a wholly-owned subsidiary of EnergyNorth, Inc.)
as of September 30, 1999 and 1998, and the related statements of
income, retained earnings and cash flows for each of the three
years in the period ended September 30, 1999. These 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 Natural Gas, Inc. as of September 30, 1999 and
1998, and the results of it operations and its 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 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 financial statements. This information has been subjected
to the auditing procedures applied in our audit of the basic
financial statements and, in our opinion, is fairly stated, in
all material respects, in relation to the basic 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 Natural Gas, Inc.
Operating Operating Net income
(In thousands) revenues income (loss) (loss) Cash dividends
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
First Quarter
1999 $22,019 $3,984 $2,992 $934
1998 27,135 4,512 3,826 935
- --------------------------------------------------------------------------------
Second Quarter
1999 36,441 7,040 6,118 934
1998 37,479 6,113 5,264 935
- --------------------------------------------------------------------------------
Third Quarter
1999 11,383 (877) (1,770) 976
1998 13,106 (816) (1,672) 1,000
- --------------------------------------------------------------------------------
Fourth Quarter
1999 6,774 (1,507) (3,509) 976
1998 7,576 (1,582) (2,505) 933
- --------------------------------------------------------------------------------
Note: 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.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
OMITTED
ITEM 11. EXECUTIVE COMPENSATION
OMITTED
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
OMITTED
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
OMITTED
<PAGE>
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:
</TABLE>
<TABLE>
<CAPTION>
Page No(s).
in this Report
----------------
<S> <C>
Statements of Income for the years ended
September 30, 1999, 1998 and 1997 18
Balance Sheets at September 30, 1999 and 1998 19
Statements of Capitalization at September 30, 1999 and 1998 20
Statements of Retained Earnings for the years
ended September 30, 1999, 1998 and 1997 21
Statements of Cash Flows for the years ended
September 30, 1999, 1998 and 1997 22
Notes to Financial Statements 23-33
Report of Independent Public Accountants 34
Supplementary Financial Information 35
</TABLE>
(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:
<TABLE>
Schedule Page No. in
Number Description this Report
------ ----------- -----------
<S> <C> <C>
II Valuation and Qualifying Accounts for the
three years ended September 30, 1999 38
Report of Independent Public Accountants 34
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.
</TABLE>
(3) Exhibits Required by Item 601 of Regulation S-K
<PAGE>
See Exhibit Index on pages 40 and 41.
(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 ENI's plan to merge with Eastern.
(c) Exhibits - See Exhibit Index on pages 41 and 42.
(d) Financial Statement Schedules
<PAGE>
<TABLE>
<CAPTION>
SCHEDULE II
ENERGYNORTH NATURAL GAS, INC.
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 Balance
Year ended beginning Charged to costs other at end
September 30, Description of period and expenses accounts(1) Deductions of period
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1999 Allowance for
doubtful accounts $1,088 $ 880 $167 $1,066 $1,069
1998 Allowance for
doubtful accounts 1,309 1,080 118 1,419 1,088
1997 Allowance for
doubtful accounts 1,176 1,190 136 1,193 1,309
</TABLE>
_____________________
(1) Represents recoveries on accounts previously written off
<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 NATURAL GAS, INC.
Date: December 17, 1999 by: /s/ Robert R. Giordano
-------------------------
Robert R. Giordano
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 and Chief Executive Officer
- ------------------------ (principal executive officer)
Robert R. Giordano
/s/ Michelle L. Chicoine Director, President and Chief Operating
- ------------------------ Officer
Michelle L. Chicoine
/s/ Frank L. Childs Director, 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
<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. is incorporated by reference to Exhibit
2.0 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441)
for the fiscal year ended September 30, 1999.
2.1 Amendment No. 1 to Agreement and Plan of Reorganization
dated November 4, 1999 is incorporated by reference to
Exhibit 2.1 to EnergyNorth, Inc.'s Form 10-K (File No.
1-11441) for the fiscal year ended September 30, 1999.
3.1 Articles of Incorporation of EnergyNorth Natural Gas,
Inc. are incorporated by reference to Exhibit 3.1
to EnergyNorth Natural Gas, Inc.'s Registration
Statement on Form S-1, No. 333-32949, dated August 6,
1997.
3.2 By-Laws of EnergyNorth Natural Gas, Inc., as amended,
are incorporated by reference to Exhibit 3.2 to
EnergyNorth Natural Gas, Inc.'s Amendment No. 2 to
Registration Statement on Form S-1, No. 333-32949, dated
September 17, 1997.
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 of
EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for
the fiscal year ended September 30, 1992.
4.4 Fifth Supplemental Indenture, dated as of
February 1, 1995, to Gas Service, Inc. General and
Refunding Mortgage Indenture, dated as of June 30, 1987,
is incorporated by reference to Exhibit 4.4 to
EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for the
fiscal year ended September 30, 1996.
4.5 Sixth Supplemental Indenture, dated as of
September 15, 1997, to Gas Service, Inc. General and
Refunding Mortgage Indenture, dated as of June 30, 1987,
is incorporated by reference to Exhibit 4.5 to
EnergyNorth Natural Gas, Inc.'s Amendment No. 1 to
Registration Statement on Form S-1, No. 333-32949, dated
September 10, 1997.
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 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, 1999.
10.4 Tax Sharing Agreement, dated as of October 1,
1988, is incorporated by reference to Exhibit 10.21 to
EnergyNorth Natural Gas, Inc.'s Registration
Statement on Form S-1, No. 333-32949, dated August 6,
1997.
10.5 Cost Allocation Agreement, dated as of October 1, 1996, is
incorporated by reference to 10.22 to EnergyNorth Natural
Gas, Inc.'s Amendment No. 2 to Registration Statement on
Form S-1, No. 333-32949, dated September 17, 1997.
27 Financial Data Schedule of the Registrant.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
EnergyNorth Natural Gas, Inc. condensed balance sheet as of September 30,
1999 and condensed statement of income and statement of cash flows for the
twelve months ended September 30, 1999 and is qualified in its entirety by
reference to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 113,730<F1>
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 20,716
<TOTAL-DEFERRED-CHARGES> 16,311
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 150,757
<COMMON> 3,000
<CAPITAL-SURPLUS-PAID-IN> 22,538
<RETAINED-EARNINGS> 19,276
<TOTAL-COMMON-STOCKHOLDERS-EQ> 44,814
0
0
<LONG-TERM-DEBT-NET> 41,993
<SHORT-TERM-NOTES> 14,178
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 412
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 49,360
<TOT-CAPITALIZATION-AND-LIAB> 150,757
<GROSS-OPERATING-REVENUE> 76,617
<INCOME-TAX-EXPENSE> 2,740
<OTHER-OPERATING-EXPENSES> 65,237
<TOTAL-OPERATING-EXPENSES> 67,977
<OPERATING-INCOME-LOSS> 8,640
<OTHER-INCOME-NET> (204)
<INCOME-BEFORE-INTEREST-EXPEN> 8,436
<TOTAL-INTEREST-EXPENSE> 4,605
<NET-INCOME> 3,831
0
<EARNINGS-AVAILABLE-FOR-COMM> 3,831
<COMMON-STOCK-DIVIDENDS> 3,820
<TOTAL-INTEREST-ON-BONDS> 3,569
<CASH-FLOW-OPERATIONS> 4,985
<EPS-BASIC> $0.00
<EPS-DILUTED> 0
<FN>
<F1>Net of accumulated depreciation of $56,126
</FN>
</TABLE>
