FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 1998
Commission File Number 333-32949
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 22, 1998, 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 22, 1998, 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 39 pages.
Exhibit Index appears on Pages 38 and 39.
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<TABLE>
<CAPTION>
TABLE OF CONTENTS
Part I Page No(s).
<C> <S> <S>
Item 1. Business
General 3-4
Gas Distribution Business 4
Summary of Revenues 5-6
Deregulation 6
Competition 6
Gas Supply
General 6
Supply Contracts and Storage 6-7
Cost of Purchased and Produced Gas 7
Supervision and Regulation 8
Employees 8
Item 2. Properties 8
Item 3. Legal Proceedings 8-10
Item 4. Submission of Matters to a Vote of Security Holders 10
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 10
Item 6. Selected Financial Data 10
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 11-16
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 16
Item 8. Financial Statements and Supplementary Data 17-33
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 33
Part III
Item 10. Directors and Executive Officers of the Registrant 33
Item 11. Executive Compensation 33
Item 12. Security Ownership of Certain Beneficial Owners and Management 33
Item 13. Certain Relationships and Related Transactions 34
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 34-36
Signatures 37
Exhibit Index 38-39
</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.
The service territory of the Company has a population of
approximately 470,000 in 27 communities situated in southern and
central New Hampshire, which includes the communities of Nashua,
Manchester, Concord and Laconia. The service area encompasses
approximately 922 square miles. Located within 30 to 85 miles of
Greater Boston, the Company's service territory offers a
favorable business climate with no general sales or personal
income taxes, a productive labor force and a comfortable, safe
and clean environment for residents and tourists.
After three years of nonfarm employment growth rates greater than
both the New England average and the national average, the state
of New Hampshire nonfarm growth rate was 1.6% in 1998. This
compares to a 2.4% average growth rate nationally and a 2.2%
average rate for New England for the same period. However,
New Hampshire employment growth in 1999 is forecasted to be 2.4%.
New housing permits increased 15.4% in 1998 compared to 1997 and
are expected to increase another 5.4% in 1999. While the New Hampshire
unemployment rate for 1999 is forecasted at 2.4% compared to 2.6%
in 1998, the labor force is forecasted to increase by 1.5% in
1999. Job growth and low unemployment in the Company's service
area tend to result in an increase in volumes transported and
sold and numbers of customers. (All employment and housing
statistics are taken from The New England Economic Project's
October 1998 Economic Outlook for New Hampshire.) In fiscal
1998, the Company experienced net growth of more than 2.4% in
total customers compared to fiscal 1997.
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.
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
<PAGE>
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 five years, the Company has experienced an annual average
customer growth rate of more than 2.3%. This compares to an
approximate 1.3% national average for local distribution
companies, according to the American Gas Association. Additional
growth in distribution operations also occurs as industrial and
commercial customers turn to natural gas for electric generation
because of a price advantage and as a means to ensure compliance
with the provisions of the Clean Air Act. As the electric
industry continues to move toward deregulation, this option has
become more attractive. The development of new gas-burning
technologies for industry has provided opportunities for
increased gas usage in market sectors that are not sensitive to
the weather.
Gas Distribution Business
The Company distributes natural gas as a regulated utility
pursuant to franchise authority granted by the State of New
Hampshire Public Utilities Commission (Commission). No
operations are outside New Hampshire. While the franchise area
of the Company is primarily residential in character, 59% of
sales volumes are commercial and industrial. As of September 30,
1998, the Company served nearly 69,600 customers, of which
approximately 88% were residential and 12% were commercial and
industrial. During fiscal 1998, no customer purchased more than
4.2% of the Company's 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, 1998,
the Company had 66 firm transportation customers.
The Company distributes gas to its utility customers through a
system of underground pipelines connected with its three
operations centers in Manchester, Nashua and Tilton, six take stations
located in Manchester, Londonderry, Windham, Concord, Hooksett
and Suncook and four production plant facilities in Manchester,
Nashua, Concord and Tilton. The pipelines are generally located
in public ways and are subject to licenses granted by
municipalities. The Company serves over 75% of New Hampshire's
natural gas customers.
On November 3, 1998, the Company filed a petition with the
Commission for authority to operate in the city of Berlin, New
Hampshire. Berlin is a community of approximately 12,000
inhabitants in the
<PAGE>
northern tier of the state. The petition is supported by a
request from the State of New Hampshire Department of Corrections
to provide natural gas service to a new prison complex being
constructed in Berlin. The prison will be located approximately
one-half mile from the Portland Natural Gas Transmission System.
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, in thousands of dollars, attributable to various
categories of gas distribution and related operations (unaudited)
during the last three fiscal years are as follows:
September 30,
----------------------------------
1998 1997 1996
----------------------------------
Sales service $82,686 $91,670 $76,007
Transportation service 2,610 1,308 1,503
Service and appliance sales 1,910 1,949 1,781
Rentals 686 750 821
----------------------------------
$87,892 $95,677 $80,112
==================================
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.
Deregulation
The Company has been providing gas transportation rates and
separate standby and balancing services for commercial and
industrial customers since late 1993.
Gas transportation services have allowed customers to utilize the
Company's distribution system for the transportation of gas
purchased from third-party gas marketers, creating competition
from gas marketers for the sale of gas to end users. At
September 30, 1998, the Company had 66 firm transportation
customers. These customers are, for the most part, large
commercial and industrial customers. The volume transported for
firm transportation customers in fiscal 1998 was 1.5 Bcf,
approximately 13% of 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 other classes of customers. Recommendations
to the Commission are not expected until late summer of 1999. The
Company cannot predict the outcome of the proceeding, or
the impact on transportation volumes or customers. The Company
expects the number of transportation customers and the volume of gas
transported to increase.
<PAGE>
The Company is the sole distributor and transporter of natural
gas in its franchise area. The Tennessee Gas Pipeline Company
("Tennessee") is the only interstate pipeline to serve the
Company's franchise area. 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 who 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.
Gas Supply
General. The Company's gas supply goal is to maintain a balanced
portfolio of supply that will continue to minimize the overall
cost of gas while providing the necessary security to meet demand
requirements.
Supply Contracts and Storage. The Company's gas supply is
principally natural gas transported by the interstate pipeline
system. The Company has contracted with Tennessee to deliver
56,833 Dekatherms ("Dths," a unit of heating value equivalent to
one million British Thermal Units) per day on a firm
transportation basis with an additional 8,000 Dths per day on an
interruptible basis. The Company also contracted with a New
England supplier for city gate delivery of 8,000 Dths per day
(151 day service). Natural gas supplies are purchased with both
long-term and short-term firm contracts. During fiscal year
1998, the Company purchased approximately 1.8% of its annual
natural gas requirements with short-term contracts. The Company
did not purchase supply on the spot market in fiscal year 1998.
The Company's long-term contracts, under which it has firm supply
for approximately 40,529 Dths per day, have remaining terms of
one to eight years.
In fiscal 1998, approximately 56% of the gas delivered by the
Company came from domestic pipeline sources, 19% from Canadian
pipeline supplies and approximately 11% from supplemental pipeline
supplies. LP and liquefied natural gas (LNG) purchases from both
domestic and foreign sources made up approximately 1% of the gas
delivered by the Company. Supplemental supplies of gas are
<PAGE>
produced from plants owned and operated by the Company.
Third-party marketer supply to end users on the Company's system
accounted for 13%.
All pipeline volumes are transported by Tennessee under FERC
tariffed rate schedules. The supply from Canada is transported
to Tennessee's system using the TransCanada and the Iroquois Gas
transmission systems.
In addition to long-term supply sources, the Company stores gas
during the summer months under long-term contracts with the
owners of storage facilities located in Pennsylvania and New
York. Gas from these storage facilities, up to 24,304 Dths per
day on a firm basis, is delivered to the Company during the
winter months through the Tennessee system. The Company owns
other on-site storage facilities capable of holding 115,660 Dths
of LP and 13,057 Dths of LNG.
The Company has contracted for 300,000 Dths of supplemental gas
vapor, 100,000 Dths of LNG and an additional one million gallons
of LP for the winter of 1998 - 1999.
The Company expects to be able to secure the gas supply required
to meet existing customer and forecasted new customer demands
through long-term commitments and purchases in the spot market.
Cost of Purchased and Produced Gas. The average unit cost of gas
purchased and produced during the twelve months ended September
30, 1998 was approximately $4.09 per Mcf compared to $4.28 per
Mcf for the same period last year. The 1998 average unit cost
reflects the lower cost of gas supply in the marketplace. The
cost of gas adjustment (CGA) clause authorized by the Commission
permits recovery by the Company from its customers (or requires
refunds to its customers) of gas costs (including pipeline, LP,
LNG and storage) that are higher (or lower) than the cost of gas
included in base rates. The Company may adjust the approved CGA
rate upward or downward on a monthly basis. The monthly
accumulative adjustments may not exceed 10% of the approved unit
cost of gas sold. Amounts recovered through CGA rates are
reconciled twice annually against actual costs, for summer and
winter periods, and future CGA rates are adjusted accordingly.
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 1998 - 1999 winter
period. The call options provide the right, but not the
obligation, to purchase gas at a predetermined price by a certain
date. By selling a put option, the Company agrees to purchase
gas at a predetermined price by a certain date. The purchase of
call options and the sale of put options creates a collar
mechanism. The collar establishes a maximum and minimum price at
which the Company will buy gas contracts on the commodities
market. All program costs and benefits will be passed on to
customers through the CGA.
Margins earned on interruptible, 280-day sales and capacity
release are passed on to firm customers through the CGA. In
addition, costs associated with a fuel inventory trust, including
administration fees and carrying costs, are recovered through the
CGA.
<PAGE>
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.
Employees
At September 30, 1998, the Company had 105 full-time employees,
represented by two contracts with Local 12012 of the United
Steelworkers of America. The contracts expire in 2001.
Substantially all of the cost of ENI's 116 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, 1998, the Company
had approximately 1,086 miles of mains and 690 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. Substantially all of the Company's utility
properties are subject to the liens of the indentures securing
the Company's First Mortgage Bonds. In some cases, motor
vehicles and nonutility assets are subject to purchase money
security interests held by banks.
ITEM 3. LEGAL PROCEEDINGS
In addition to the matters described below, the Company is a
party in several proceedings of the sort that arise in the
ordinary course of its business. Such actions, for the most
part, are covered by insurance and, to the extent that they
are not fully covered, the damages sought are not material
in amount. The Company is a party to various routine Commission
proceedings relating to operations, none of which is expected to
have a material impact on the Company's earnings or assets.
The Company and certain of its predecessors owned or operated
several facilities for the manufacture of gas from coal, a
process used through the mid-1900s that produced by-products that
may be considered contaminated or hazardous under current law,
and some of which may still be present at such facilities. The Company
accrues environmental investigation and cleanup costs with respect to
<PAGE>
former manufacturing sites and other environmental matters when it is
probable that a liability exists and the amount or range of amounts
can be reasonably estimated.
The New Hampshire Department of Environmental Services (NHDES)
has required remedial action for a portion of the Concord site at
which wastes were disposed from approximately 1852 through 1952.
The estimated cost to complete this remedial action ranges from
$1.9 million to $4.0 million, and the Company has recorded $1.9
million at September 30, 1998 in deferred charges. The Company
has received an order from the Commission approving recovery from
customers, over a seven-year period, of substantially all costs,
excluding carrying costs, of past and future investigation,
remediation and recovery efforts for the Concord site. Recovery
of costs incurred through April 30, 1998 began on June 1, 1998.
The total unamortized balance for the Concord site, including the
gasholder site, of $5.5 million at September 30, 1998 is excluded
from rate base. The Company may not earn a return or charge
rates to customers based on amounts not included in rate base.
The Company has instituted several lawsuits to recover the costs
of investigation and remediation of the Concord site. On
December 8, 1995, the Company filed suit in the United States
District Court for the District of New Hampshire against
Associated Electric and Gas Insurance Services, Ltd., American
Home Assurance Company, CIGNA Specialty Insurance Company,
International Insurance Company, Lloyd's, Underwriters at London,
Lexington Insurance Company and National Union Fire Insurance
Company, later adding Columbia Casualty Company as a defendant,
seeking declaratory judgment that they owe the Company a
defense and/or indemnification for environmental claims
associated with the Concord facility. The Company filed suit in
the New Hampshire (Hillsborough County) Superior Court on
December 8, 1995 against the Continental Insurance Company and
Netherlands Insurance Company seeking a declaratory judgment
that they owe the Company a defense and/or indemnification for
environmental claims associated with the Concord facility.
At the direction of NHDES, the Company and Public Service
Company of New Hampshire (PSNH), an electric utility company,
conducted an environmental site characterization of a former
manufactured gas plant in Laconia, New Hampshire. The Laconia
manufactured gas plant operated between approximately 1887 and 1952,
and the Company owned and operated the facility for approximately the
last seven years of its active life. Without admitting liability,
the Company and PSNH entered into an agreement under which the costs
of the site characterization were shared. The Company's share of the
costs of the site characterization and a report to the NHDES totaled
$409,000 and has been recorded in deferred charges as of
September 30, 1998. The report describes conditions at the site,
including the presence of by-products of the manufactured gas
process in site soils, groundwater and sediments in an adjacent
water body. Based upon its review of the report, the NHDES has
directed PSNH and the Company to prepare and submit a remedial
action plan. The Company has recorded an additional $150,000 in
deferred charges at September 30, 1998, for risk characterization
studies at the Laconia site and a remedial action plan. The
Company expects to incur further costs but is currently unable to
predict the magnitude of any liability that may be imposed on it
for the cost of additional studies or the performance of a remedial
action in connection with the Laconia site. The Company commenced
proceedings in New Hampshire Superior Court and Federal District
Court on February 2, 1997 against eighteen of its present and
former insurers seeking recovery of expenses that have been and will be
<PAGE>
incurred in connection with the investigation and remediation of
contamination from the Laconia plant.
Through November 1998, the Company reached settlements with
defendants in gasholder related envionmental lawsuits in an
aggregate amount of $3.5 million and further payment to the
Company of a portion of future Concord site remediation costs.
The Company expects that such settlement amounts will reduce the
amount that it will be permitted by the Commission to recover
from its ratepayers.
During 1998, the Company received a notice of potential
responsibility from the Environmental Protection Agency related
to a site in the area of its former gas manufacturing plant in
Nashua, New Hampshire. The Company's share of costs for the
disposal of contaminants at the site are estimated to range from
$300,000 to $350,000 and the Company recorded $300,000 in
deferred charges at September 30, 1998. The Company subsequently
received a request from the NHDES to investigate the former gas
manufacturing site in Nashua, New Hampshire. The Company expects
to incur cost but is currently unable to predict the magnitude of
any liability that may be imposed on it for cost of studies or
the performance of remedial action in connection with the Nashua
site.
The Company is pursuing and intends to pursue recovery from
insurance carriers and claims against any other responsible
parties seeking to ensure that they contribute appropriately to
reimburse the Company for any costs incurred with respect to
environmental matters. The Company intends to seek and expects
to receive approval of rate recovery methods with respect to
environmental matters after it has determined the extent of
contamination, received recommendations with regard to
remediation and commenced remediation efforts.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
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 EnergyNorth, Inc.
ITEM 6. SELECTED FINANCIAL DATA
OMITTED
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Earnings
Warmer weather in the Company's service territory significantly
impacted net income, which declined to $4.9 million in 1998 from
$6 million in 1997. Temperatures were 12.9% warmer than normal
and 11.4% warmer than the prior year. The effect of weather,
when compared to normal, reduced 1998 utility margin by $1.7
million after taxes; whereas, warmer temperatures in 1997
decreased utility margin by $454,000 after taxes. In addition,
1997 earnings were $649,000 higher than 1998 as a result of a
favorable net property tax settlement that was recorded in 1997.
Partially offsetting the 1998 decrease in net income was
continued customer growth and successful efforts to contain
operating costs.
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 the Company's firm customers.
The Company's tariff includes CGA rates that provide for
increases and decreases in the rates charged for gas to reflect
estimated changes in the cost of gas. Although changes in CGA
rates affect revenues, they do not affect total margin because
the CGA is a tariff mechanism designed to provide dollar-for-
dollar recovery of gas costs. Amounts recovered through CGA
rates are reconciled at least semiannually against actual costs,
and future CGA rates are adjusted accordingly.
The Company's sales are responsive to colder weather because the
majority of firm customers use natural gas for space heating
purposes. The Company measures weather through the use of degree
days. A degree day is calculated by subtracting the average
temperature for the day from 65 degrees Fahrenheit. The "normal"
number of degree days during any period is calculated based upon
a rolling approximate 30-year average number of degree days
during such period. The table below discloses degree day data as
recorded at the U.S. weather station in Concord, New Hampshire,
comparing actual degree days to the previous period and to
normal. Because of the
<PAGE>
size and topographical variations of the Company's service territory,
weather conditions within such territory often vary. The Company
considers Concord, New Hampshire weather data to be representative of
weather conditions within its service territory.
<TABLE>
<CAPTION>
Degree days
---------------------------
Prior Change vs. Change vs.
Actual period Normal prior period normal
---------------------------------------------------------
<C> <S> <S> <S> <S> <S>
Fiscal year ended September 30, 1998 6,532 7,373 7,499 (11.4)% (12.9)%
Fiscal year ended September 30, 1997 7,373 7,482 7,506 (1.5)% (1.8)%
Fiscal year ended September 30, 1996 7,482 6,834 7,549 9.5% (.9)%
</TABLE>
Operating revenues were $85.3 million in 1998 compared to $93 million in 1997,
an 8.3% decrease. Firm sales gas revenues in 1998 were $78.8 million compared to
$85.7 million in 1997. Firm transportation revenues of $2.4 million were twice
the level achieved in 1997. The weather in 1998 was 12.9% warmer than normal
and 11.4% warmer than the previous year. Growth in the average number of
customers of 2.4% in 1998 helped mitigate the effects of the warmer
temperatures. Firm sendout, including transportation, was 11.6 Bcf compared to
11.5 Bcf in 1997. Volumes transported increased more than 121%. This increase
included a shift of 207,000 Mcf from firm commercial and industrial sales to
transportation, representing a decrease of $900,000 in operating revenues
attributable to the commodity cost of gas.
Shifts between transportation and sales gas will cause variations in natural gas
revenues since the transportation rate does not include the commodity cost of
gas, which is billed directly to customers by their marketers. The Company's
rate structure provides for transportation service margin that is approximately
2.4% less than sales service margin. At September 30, 1998, the Company had 66
firm transportation customers compared to 45 customers the previous year.
The Company is currently involved in a proceeding at the Commission to examine
further unbundling of the natural gas industry in New Hampshire. The Company
cannot predict the outcome of this proceeding or potential impact on operating
income.
Cost of Gas Sold
The cost of gas sold was $46.7 million in 1998 compared to $54.6 million in
1997. The decrease was primarily due to lower volumes of gas sold
($6.1 million) and a decline in the unit cost ($2.4 million). The average
unit cost of gas sold in 1998 was $4.09 per Mcf compared to $4.28 per Mcf
in 1997. Decreases or increases in purchased gas costs from suppliers have
no significant impact on margin, as they are passed on to customers through
the CGA.
Operating Expenses
Operations and maintenance expense for fiscal year 1998 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
<PAGE>
efforts, which offset increases in labor costs and health insurance and other
employee benefit costs.
Depreciation and amortization expense increased 8.3% in 1998 and reflects
continued expansion, including the full impact of the Company's major main
extension to serve Milford, New Hampshire, which was completed in late fiscal
year 1997. Depreciation and amortization expense also includes normal upgrades
to the distribution system and related facilities and amortization of
environmental remediation costs. Net additions to property, plant and equipment
were $13.2 million and $12 million in 1998 and 1997, respectively.
Taxes other than income taxes increased more than $1.1 million to $3.7 million
in 1998. The 1997 results include a favorable property tax settlement, net of
adjustments, of more than $1 million.
The lower level of pretax income is the main reason for the $666,000 decrease in
federal and state income taxes in 1998.
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 1998 were capital expenditures of $13.2
million, dividend payments of $3.8 million, environmental remediation of
$661,000 and retirement of $515,000 of long-term debt. These expenditures were
funded primarily through cash generated from current operations and short-term
borrowings. Borrowings against lines of credit during 1998 ranged from zero to
a high of $3.6 million. In addition, at September 30, 1998, deferred gas cost
was in an overcollected position resulting from winter and summer activity. The
overcollected amounts will be returned to customers through the CGA mechanism.
Capital expenditures for 1999 are currently projected at approximately $11.6
million. Additional cash requirements will be necessary for the payment of
dividends, environmental remediation, annual sinking fund requirements and
maturities of long-term debt and working capital. Cash to fund these
requirements is expected to be provided principally by internally generated
funds and short-term bank borrowings under the Company's lines of credit. At
September 30, 1998, the Company had available lines of credit aggregating $15
million, $1.9 million of which was outstanding. In addition, a credit line of
$10.5 million was available at September 30, 1998, under the Company's fuel
inventory trust financing plan. At September 30, 1998, the Company's fuel
<PAGE>
inventory in trust in the balance sheet was $8.7 million with an outstanding
purchase obligation of $8.7 million.
On September 30, 1998, the Company's capitalization ratio consisted of 50%
common equity and 50% 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.
Results of Operations 1997 Compared to 1996
Net income increased to $6 million in 1997 from 1996 net income of $5.4 million.
The 1997 increase in earnings was due primarily to successful efforts to contain
operating costs.
Operating revenues were $93 million in 1997, an increase of 20% from 1996. The
increase resulted primarily from higher CGA rates. The average unit cost of gas
sold in 1997 was $4.28 per Mcf compared to $3.96 per Mcf in 1996. Weather in
the Company's service territory was 1.5% warmer than 1996, although the November
- - March winter heating season was 7.3% warmer. The total volume of gas
delivered to customers increased more than 2%. Partially offsetting the impact
of the warmer temperatures was the 2.2% growth in the average number of
customers.
Operations and maintenance expense was approximately the same as the prior year.
Reductions in the work force, other cost saving initiatives and workers'
compensation and health insurance refunds helped offset most of the increases
from liability insurance, uncollectible accounts and other administrative
expenses.
Taxes other than income taxes decreased almost $1.1 million to $2.6 million, due
primarily to a favorable property tax settlement, net of adjustments, of more
than $1 million, which offset property tax rate increases and additions to
taxable property.
New Accounting Standards and Pronouncements
During fiscal year 1998, the Company implemented Statement of Financial
Accounting Standards (SFAS) No. 128, "Earnings per Share," which establishes
standards for computing and presenting earnings per share, and SFAS No. 129,
"Disclosure of Information about Capital Structure," which establishes standards
for disclosure requirements regarding capital structure. Both SFAS No. 128 and
No. 129 have no material impact on the Company's financial reporting.
<PAGE>
The Financial Accounting Standards Board issued new accounting standards which
the Company will adopt in future periods. SFAS No. 130, "Reporting
Comprehensive Income," establishes standards for reporting and the disclosure of
comprehensive income and its components. This standard is effective in fiscal
year 1999 and is not expected to have a material impact on the Company's
financial reporting. SFAS No. 131, "Disclosures About Segments of an Enterprise
and Related Information," requires disclosure of operating segments, including
disclosures about products and services, geographic areas and major customers.
It is effective in fiscal year 1999 and is not expected to have a material
impact on the Company's financial reporting. SFAS No. 132, "Employer's
Disclosures About Pensions and Other Postretirement Benefits," revises
employer's disclosures about pension and other postretirement benefit plans. It
does not change the measurement of recognition of those plans. Effective in
fiscal year 1999, the standard is not expected to have a significant impact on
the Company's financial reporting. SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," establishes standards for recording all
derivative instruments as assets and liabilities measured at fair value. The
standard is effective in the fourth quarter of fiscal year 1999 and is not
expected to have a material impact on the Company's financial position.
The American Institute of Certified Public Accountants issued Statement of
Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed
and Obtained for Internal Use," and SOP 98-5, "Reporting on the Costs of Start-
up Activities." Both are effective in fiscal year 2000 and adoption is not
expected to have a material impact on the Company's financial position.
Year 2000 Readiness
The Company has evaluated its principal computer systems and noninformation
technology systems including, but not limited to, telecommunication systems,
automated meter reading systems, SCADA, regulator stations, plant remote control
systems and security systems to determine readiness for the year 2000. These
systems are currently capable of processing the year 2000, or are in the process
of being upgraded or replaced by systems that are similarly capable. All
necessary program modifications and system upgrades and testing are expected to
be completed by the year 2000. Costs incurred to date and costs expected to be
incurred to complete the year 2000 readiness are not significant and
will not have a material impact on the Company's financial position or results
of operations. The Company is currently assessing year 2000 issues with third
parties with whom it has a material relationship. Except for the Company's
major pipeline supplier, who has provided assurance of compliance, the Company
has not determined the level of third-party risk. Preparation of a contingency
plan to address failure of various systems is in process and is expected to be
finalized prior to September 30, 1999.
Factors That May Affect Future Results
The Private Securities Litigation Reform Act of 1995 encourages the use of
cautionary statements accompanying forward-looking statements. The preceding
Management's Discussion and Analysis of Financial Condition and Results of
Operations includes forward-looking statements concerning the impact of changes
in the cost of gas and of the CGA mechanism on total margin;
<PAGE>
projected capital expenditures and sources of cash to fund expenditures; impact
of unbundling regulatory proceedings; year 2000 readiness and estimated costs
of environmental remediation and anticipated regulatory approval of recovery
mechanisms. The Company's future results, generally and with respect to such
forward-looking statements, may be affected by many factors, among which are
uncertainty as to the regulatory allowance of recovery of changes in the cost
of gas; uncertain demands for capital expenditures and the availability of cash
from various sources; uncertainty as to whether transportation rates will be
reduced in future regulatory proceedings with resulting decreases in
transportation margins; uncertainty as to environmental costs and as to
regulatory approval of the full recovery of environmental costs, transition
costs and other regulatory assets; weather; results of regulatory proceedings
on unbundling; impact of new pipeline supplies and success of the Company's
year 2000 readiness efforts and those of its vendors and customers.
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, 1998 1997 1996
- -----------------------------------------------------------------------------
Operating revenues:
Utility gas service $84,274 $91,965 $76,620
Other 1,022 1,013 890
------------------------------------
Total operating revenues 85,296 92,978 77,510
------------------------------------
Operating expenses:
Cost of gas sold 46,693 54,633 39,115
Operations and maintenance 18,445 18,397 18,624
Depreciation and amortization 5,381 4,969 4,693
Taxes other than income taxes 3,738 2,590 3,654
Federal and state income taxes 2,812 3,478 3,224
------------------------------------
Total operating expenses 77,069 84,067 69,310
------------------------------------
Operating income 8,227 8,911 8,200
Other income 1,111 792 735
Interest expense:
Interest on long-term debt 3,628 2,657 2,747
Other interest 797 1,061 761
------------------------------------
Total interest expense 4,425 3,718 3,508
------------------------------------
Net income $ 4,913 $ 5,985 $ 5,427
====================================
The accompanying notes are an integral part of these financial statements.
<PAGE>
<TABLE>
<CAPTION>
Balance Sheets EnergyNorth Natural Gas, Inc.
(In thousands)
September 30, 1998 1997
- -------------------------------------------------------------------------------------------------------
<C> <S> <S>
Assets
Property:
Utility plant, at cost $158,564 $146,799
Accumulated depreciation and amortization 51,309 47,811
----------------------
Net utility plant 107,255 98,988
----------------------
Current assets:
Cash and temporary cash investments 1,756 2,753
Accounts receivable (net of allowances of $1,088 in 1998 and $1,309 in 1997) 1,828 2,997
Unbilled revenues 516 602
Materials and supplies 1,411 1,650
Supplemental gas supplies 9,479 8,929
Prepaid and deferred taxes 1,766 1,180
Recoverable FERC 636 transition costs 252 1,261
Prepaid expenses and other 2,028 2,006
----------------------
Total current assets 19,036 21,378
----------------------
Deferred charges and other assets:
Regulatory asset - income taxes 2,401 2,401
Recoverable environmental costs 6,113 6,546
Other deferred charges and assets 1,970 1,948
----------------------
Total deferred charges and other assets 10,484 10,895
----------------------
Total assets $136,775 $131,261
======================
Stockholder's equity and liabilities
Capitalization (see accompanying statements) $ 87,235 $ 86,606
----------------------
Current liabilities:
Notes payable to banks 1,891 -
Current portion of long-term debt 450 484
Inventory purchase obligation 8,712 7,852
Accounts payable 4,670 5,333
Accounts payable to affiliates 2,145 2,433
Deferred gas costs 3,841 1,300
Accrued interest 257 303
Accrued and deferred taxes 524 82
Accrued FERC 636 transition costs 252 1,261
Accrued environmental remediation costs 2,345 1,546
Customer deposits and other 1,313 1,322
----------------------
Total current liabilities 26,400 21,916
----------------------
Commitments and contingencies
Deferred credits:
Deferred income taxes 17,930 17,401
Unamortized investment tax credits 1,610 1,734
Regulatory liability - income taxes 1,141 1,254
Contributions in aid of construction and other 2,459 2,350
----------------------
Total deferred credits 23,140 22,739
----------------------
Total stockholder's equity and liabilities $136,775 $131,261
======================
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
Statements of Capitalization EnergyNorth Natural Gas, Inc.
(In thousands, except share information)
September 30, 1998 1997
- --------------------------------------------------------------------------------
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 22,538 22,538
Retained earnings 19,265 18,155
---------------------
Total common stockholder's equity 44,803 43,693
---------------------
Long-term debt:
First Mortgage Bonds
Due 2009 8.44% 3,667 4,000
Due 2019 9.70% 7,000 7,000
Due 2020 9.75% 10,000 10,000
Due 2027 7.40% 21,975 22,000
Notes payable
Due through 2001 prime plus .50% 240 397
---------------------
42,882 43,397
Less current portion 450 484
---------------------
Total long-term debt 42,432 42,913
---------------------
Total capitalization $87,235 $86,606
=====================
The accompanying notes are an integral part of these financial statements.
<PAGE>
Statements of Retained Earnings EnergyNorth Natural Gas, Inc.
(In thousands)
For the years ended September 30, 1998 1997 1996
- ------------------------------------------------------------------------------
Balance at beginning of year $18,155 $15,819 $14,027
Add - net income 4,913 5,985 5,427
-----------------------------------
23,068 21,804 19,454
Deduct - cash dividends on common stock 3,803 3,649 3,635
-----------------------------------
Balance at end of year $19,265 $18,155 $15,819
===================================
The accompanying notes are an integral part of these financial statements.
<PAGE>
<TABLE>
<CAPTION>
Statements of Cash Flows EnergyNorth Natural Gas, Inc.
(In thousands)
For the years ended September 30, 1998 1997 1996
- -----------------------------------------------------------------------------------------------
<C> <S> <S> <S>
Cash flows from operating activities:
Net income $ 4,913 $ 5,985 $ 5,427
Noncash items:
Depreciation and amortization 5,837 5,411 5,177
Deferred taxes and investment tax credits, net 292 1,526 1,017
Changes in:
Accounts receivable, net 1,169 (1,166) 90
Unbilled revenues 86 (20) 4
Inventories (311) (301) (881)
Prepaid expenses and other (22) (165) (58)
Deferred gas costs 2,542 5,083 (9,428)
Accounts payable (662) 46 980
Accounts payable to affiliates, net (288) 1,844 (696)
Accrued liabilities (24) (512) (163)
Accrued/prepaid taxes (143) (1,153) 1,536
Payments for environmental costs and other 257 (3,214) (821)
------------------------------
Net cash provided by operating activities 13,646 13,364 2,184
------------------------------
Cash flows from investing activities:
Additions to property (13,152) (11,977) (7,496)
------------------------------
Cash flows from financing activities:
Capital contributions from parent - - 1,500
Cash dividends on common stock (3,803) (3,649) (3,635)
Issuance of long-term debt - 22,217 208
Repayment of long-term debt (515) (7,568) (1,664)
Repayment of capital lease obligations - (25) (43)
Change in notes payable to banks 1,891 (9,535) 8,035
Change in inventory purchase obligation 860 (15) 738
Change in other financing activities 76 (370) 80
------------------------------
Net cash (used for) provided by financing activities (1,491) 1,055 5,219
------------------------------
Net (decrease) increase in cash and temporary cash investments (997) 2,442 (93)
Cash and temporary cash investments, beginning of year 2,753 311 404
------------------------------
Cash and temporary cash investments, end of year $ 1,756 $ 2,753 $ 311
==============================
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 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 Adjustment Clause
The Company's tariff includes a cost of gas adjustment (CGA)
clause that permits billings to customers for changes in its cost
of gas over a base period cost. The tariff provides for a CGA
calculation for a summer period and a winter period. The Company
may adjust the approved CGA rate upward or downward on a monthly
basis. The monthly cumulative adjustments may not exceed 10% of
the approved unit cost of gas sold. Any difference remaining
between the cost of gas incurred and amounts billed to customers
at the end of each summer or winter period is deferred for rate-
making and accounting purposes to the next corresponding summer
or winter period. Interest accrues on these amounts at the prime
rate, adjusted quarterly.
Inventories
Inventories are valued on the basis of the lower of average cost
or market.
Depreciation
The Company provides for depreciation on the straight-line basis.
The rates applied are approved by the Commission. Such rates
were equivalent to a composite rate of 3.4% for each of the years
ended September 30, 1998, 1997 and 1996. Under depreciation
practices required by the Commission, when gas utility assets under
the composite method are retired from service, the cost of the
retired assets is
<PAGE>
removed from the property accounts and charged,
together with any cost of removal, to the accumulated
depreciation accounts. For all other assets, when assets are
sold or retired, the cost of the assets and their related
accumulated depreciation are removed from the respective
accounts, net removal costs are recorded and any gain or loss is
included in income.
Deferred Charges
Total deferred charges consist primarily of regulatory assets and
the cost of issuing debt. The Company has established various
regulatory assets in cases where the Commission has permitted, or
is expected to permit, recovery of specific costs over a period
of time. At September 30, 1998, regulatory assets included $6.1
million for environmental investigation and remediation costs and
$2.4 million of unrecovered deferred state income taxes (see Note
6).
The unamortized cost of issuing debt at September 30, 1998 is $2
million. Deferred financing costs are amortized over the life of
the related security. Other deferred charges are amortized over
the recovery period specified by the Commission.
Investment Tax Credits
Investment tax credits are amortized over the estimated useful
life of the property that gave rise to the credit.
Fair Value of Financial Instruments
Because of the short maturity of certain assets, which include
cash, temporary cash investments and accounts receivable, and
certain liabilities, which include accounts payable and notes
payable to banks, these instruments are stated at amounts that
approximate fair value.
If long-term debt outstanding at September 30, 1998 had been
refinanced using new issue debt rates of interest that on average
are lower than the outstanding rates, the present value of those
obligations would have increased from the amounts outstanding in
the September 30, 1998 accompanying balance sheet by 20.6%. 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 is
immediately recognized in earnings. If such derivative is
terminated early for other economic reasons,
<PAGE>
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, 1998:
Notional Volumes Hedges of NYMEX Contracts
- ----------------------------------------------------------------------
Calls - MMBtu Purchases 302
Puts - MMBtu Sales 302
$ Amount (In thousands)
- ----------------------------------------------------------------------
Deferred gains, net $131
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires the use of
estimates and assumptions that affect assets and liabilities, the
disclosure of contingent assets and liabilities, and revenues and
expenses. Actual amounts could differ from those estimates.
Reclassifications
Reclassifications are made periodically to previously issued
financial statements to conform to the current year's
presentation.
Note 2. Cash Flows
Supplemental disclosures of cash flow information were as follows
(in thousands):
1998 1997 1996
- --------------------------------------------------------------------
Cash paid during the year for:
Interest (net of amount capitalized) $3,957 $3,821 $3,369
Income taxes 2,761 3,557 508
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 CGA.
The bank credit agreement provides for a .375% commitment fee on
the credit line and interest at prime (8.25% at September 30,
1998) with a fixed-rate interest option at less than prime on the
outstanding balance. The trust agreement provides for a
management fee of $8,000 annually. The credit agreement between
the trust and the bank provides for a total commitment of up to
$10.5 million through February 1999.
As of September 30, 1998 and 1997, the gas inventories under the
trust agreement and controlled by the Company totaled $8.7
million and $7.8 million, respectively, and are included in
inventories in the accompanying 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, 1998, the Company had $15 million available
under various unsecured bank lines of credit that are renewed
annually, $1.9 million of which was outstanding. The weighted
average interest rate on borrowings outstanding on September 30,
1998 was 8.2%. 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, 1998 are as
follows (in thousands):
Fiscal year Amount
- -----------------------------------------------------------------
1999 $450
2000 429
2001 362
2002 333
2003 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, 1998 and 1997, a SFAS No. 109 related regulatory
liability amounted to $892,000 and $960,000, respectively, for
the tax benefit of unamortized investment tax credits, and
$249,000 and $294,000, respectively, for the excess reserves for
deferred taxes as a result of pre-July 1, 1987 deferred income
taxes that were recorded in excess of the current federal
statutory income tax rate.
A deferred state income tax liability and a corresponding
regulatory asset of approximately $2.4 million, representing
revenues the Company expects to recover from 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, 1998 and 1997 were as follows (in thousands):
1998 1997
- ---------------------------------------------------------------------
Deferred tax assets:
Deferred gas costs $ 1,450 $ 240
Contributions in aid of construction 759 726
Unamortized investment tax credits 545 590
Allowance for doubtful accounts 419 506
Other 1,126 942
----------------------
Total deferred tax assets 4,299 3,004
----------------------
Deferred tax liabilities:
Property-related 17,073 15,957
Environmental costs 1,455 1,936
Other 1,972 1,787
----------------------
Total deferred tax liabilities 20,500 19,680
----------------------
Net deferred tax liability $16,201 $16,676
======================
<PAGE>
Deferred income taxes were classified in the accompanying balance sheets at
September 30, 1998 and 1997 as follows (in thousands):
1998 1997
- ----------------------------------------------------------------------------
Current $(1,729) $ (725)
Long-term 17,930 17,401
-------------------------
Total $16,201 $16,676
=========================
The components of federal and state income taxes reflected in the accompanying
statements of income for the years ended September 30, 1998, 1997 and 1996 were
as follows (in thousands):
1998 1997 1996
- -------------------------------------------------------------------------
Federal:
Current $2,702 $3,369 $ (323)
Deferred (268) (378) 3,119
Investment tax credits (124) (136) (140)
----------------------------------
Total federal 2,310 2,855 2,656
----------------------------------
State:
Current 555 701 (129)
Deferred (53) (78) 697
----------------------------------
Total state 502 623 568
----------------------------------
Total provision for income taxes $2,812 $3,478 $3,224
==================================
The total federal and state income tax provision, as a percentage of income
before federal and state income taxes, was 36.4%, 36.7% and 37.3% for the years
ended September 30, 1998, 1997 and 1996, respectively. The following table
reconciles the income tax provision calculated using the federal statutory tax
rate of 34% to the book provision for federal and state income taxes
(in thousands):
1998 1997 1996
- -------------------------------------------------------------------------------
Tax calculated at statutory rate $2,627 $3,217 $2,941
Increase (reduction) in effective tax resulting from:
Amortization of investment tax credit (124) (136) (140)
Adjustment due to change in tax rates (28) (28) (28)
State taxes, net of federal tax benefit 331 411 375
Other, net 6 14 76
------------------------
Total provision for income taxes $2,812 $3,478 $3,224
========================
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
<PAGE>
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.
Net periodic pension cost included the following components
(in thousands):
1998 1997 1996
- ---------------------------------------------------------------------------
Service cost for benefits earned $ 245 $ 229 $ 249
Interest cost on projected benefit obligations 537 509 472
Actual return on plan assets (201) (1,975) (542)
Net amortization and deferral (531) 1,311 (90)
Parent company allocation 402 427 344
-------------------------
Net periodic pension cost $ 452 $ 501 $ 433
=========================
The following table sets forth the funded status of the plans at September 30,
1998, 1997 and 1996 (in thousands):
1998 1997 1996
- ---------------------------------------------------------------------------
Vested benefit obligation $7,248 $6,286 $5,983
==========================
Accumulated benefit obligation $7,513 $6,553 $6,228
==========================
Projected benefit obligation $8,425 $7,336 $6,971
Plan assets at fair value 9,166 9,135 7,300
--------------------------
Funded status 741 1,799 329
Unrecognized transition asset (265) (325) (384)
Unrecognized prior service cost 239 295 351
Unrecognized net loss (gain) 372 (851) 447
--------------------------
Prepaid pension $1,087 $ 918 $ 743
==========================
Assumptions used to determine the projected benefit obligation were as follows:
1998 1997 1996
- ---------------------------------------------------------------------------
Discount rate 7.0% 7.5% 7.5%
Rate of increase in future compensation levels 4.0 4.0 4.0
Expected long-term rate of return on assets 9.0 9.0 9.0
Plan assets are invested in common stocks and bonds.
The Company has an employee 401(k) savings and investment plan
covering substantially all employees. The Company made
contributions of $87,000, $85,000 and $61,000 for the years ended
September 30, 1998, 1997 and 1996, respectively.
<PAGE>
Other Postemployment Benefits
In addition to providing pension benefits, the Company provides
certain health care and life insurance benefits to qualified
retired employees.
The expense recorded in fiscal 1998, 1997 and 1996 for providing
postretirement benefits, including amortization of the
accumulated projected benefit obligation over a 20-year period,
was $230,000, $216,000 and $222,000, 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.
The following table sets forth the funded status of the plan at
September 30, 1998 and 1997 (in thousands):
1998 1997
- -------------------------------------------------------------------------------
Accumulated postretirement benefit obligation as of July 31:
Retirees $ 1,106 $ 1,299
Fully eligible active plan participants 549 480
Other active participants 784 743
-----------------
2,439 2,522
Plan assets at fair market value (1,248) (1,064)
Unrecognized transition obligation (2,101) (2,241)
Unrecognized net gain 966 836
-----------------
Accrued postretirement benefit cost at July 31 56 53
Contributions for the two-month period ended September 30 57 54
-----------------
Accrued postretirement benefit cost at September 30 $ (1) $ (1)
=================
The components of net periodic postretirement benefit cost at September 30, 1998
and 1997 were as follows (in thousands):
1998 1997
- -------------------------------------------------------------------------------
Service cost - benefits attributed to services during the year $ 50 $ 48
Interest cost on accumulated postretirement benefit obligation 186 167
Actual asset return (76) (190)
Net amortization and deferral 70 191
--------------
Net periodic postretirement benefit cost $230 $ 216
==============
A 9% average annual rate of increase in the per capita costs of
covered health care benefits was assumed for fiscal 1998, reduced
in steps of 1% to a level of 5% at 2002 and thereafter. This
decrease results from changes in estimates of future health care
inflation, assumed changes in health care utilization and related
effects. Increasing the assumed health care cost trend rates by
one percentage point in each year would have resulted in a
$98,000 increase in the accumulated postretirement benefit
obligation as of July 31, 1998 and an increase in the aggregate
of the service cost and interest cost components of net periodic
postretirement benefit cost of $10,000 for fiscal 1998. A discount
rate of 7% was used to determine the accumulated postretirement
<PAGE>
benefit obligation. The expected long-term rate of return on plan
assets is 9%. Plan assets are invested in common stocks and bonds.
Note 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, 1998, are approximated as follows
(in thousands):
Fiscal year Amount
- -----------------------------------------------------------------
1999 $93
2000 89
2001 51
2002 28
2003 9
The total rental expense charged to operations for the years
ended September 30, 1998, 1997 and 1996 was approximately
$807,000, $947,000 and $973,000, 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 CGA. 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 owned or operated
several facilities for the manufacture of gas from coal, a
process used through the mid-1900s that produced by-products that
may be considered contaminated or hazardous under current law,
and some of which may still be present at such facilities. Like
other companies in the natural gas industry, the Company is a
party to governmental actions associated with former gas
manufacturing sites.
The Company is engaged in remedial action at a former gas
manufacturing site in Concord, New Hampshire, and is
participating with Public Service Company of New Hampshire in
ongoing site assessment and evaluation of remedial options at a
site located in Laconia, New Hampshire. The Company received a notice
of potential responsibility from the Environmental Protection Agency
<PAGE>
related to a site in the area of its former gas manufacturing plant in
Nashua, New Hampshire, and also received a request from the New Hampshire
Department of Environmental Services to investigate this former gas
manufacturing site. Costs to complete remedial action at the Concord site
and the Company's share of investigation and evaluation costs at the
other sites are estimated to range from $2.3 million to $5
million. Along with costs incurred to date, the Company has
recorded $2.3 million in accrued liability at September 30, 1998,
with a corresponding charge to recoverable environmental costs.
Actual environmental remediation costs to be incurred depend on a
number of factors, and therefore future costs may differ from the
amount currently recorded as a liability. Factors that may bear
on cost include changes in remediation techniques or practices,
changes in regulatory standards and the nature and extent of
contamination at the sites. The Company accrues environmental
investigation and cleanup costs with respect to former gas
manufacturing sites and other environmental matters when it is
probable that a liability exists and the amount or range of
amounts can be reasonably estimated.
The Company has received orders from the Commission that provide
for recovery from customers, over a seven-year period, of
substantially all costs, excluding carrying costs, of past and
future investigation, remediation and recovery efforts for the
Concord site. The unamortized balance of unrecovered costs ($5.5
million at September 30, 1998) is excluded from rate base. The
Company may not earn a return or charge rates to customers based
on amounts not included in rate base.
The Company has instituted several lawsuits to recover the costs
of investigation and remediation of the Concord site and
investigation of the Laconia site. Through November 1998, the
Company reached settlements with certain of the defendants in
those suits in an aggregate amount of $3.5 million. The
settlements also include further payment to the Company of a
portion of future Concord site remediation costs. The proceeds
are being reflected as reductions in deferred charges, as shown
in the accompanying balance sheets. The Company expects that
such settlement amounts will reduce the amount that it will be
permitted by the Commission to recover from its customers.
The Company is pursuing and intends to pursue recovery from
insurance carriers and claims against any other responsible
parties seeking to ensure that they contribute appropriately to
reimburse the Company for any costs incurred with respect to
environmental matters. The Company will continue to seek and
expects to receive approval of rate recovery methods with respect
to environmental matters after it has determined the extent of
contamination, received recommendations with regard to
remediation and commenced remediation efforts.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors 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, 1998 and 1997, and the related statements of
income, retained earnings, common stockholder's equity and cash
flows for each of the three years in the period ended September
30, 1998. 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, 1998 and
1997, and the results of its operations and its cash flows for
each of the three years in the period ended September 30, 1998,
in conformity with generally accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the
basic 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 4, 1998
<PAGE>
(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
- ----------------------------------------------------------------------------
First Quarter
1998 $27,135 $4,512 $3,826 $935
1997 25,360 4,190 3,408 890
- ----------------------------------------------------------------------------
Second Quarter
1998 37,479 6,113 5,264 935
1997 43,402 6,572 5,892 891
- ----------------------------------------------------------------------------
Third Quarter
1998 13,106 (816) (1,672) 1,000
1997 16,023 (804) (1,513) 934
- ----------------------------------------------------------------------------
Fourth Quarter
1998 7,576 (1,582) (2,505) 933
1997 8,193 (1,047) (1,802) 934
- ----------------------------------------------------------------------------
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, 1998.
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
<PAGE>
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
OMITTED
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
(a) List of documents filed as part of this Report
(1) Financial Statements
The following financial statements are included herein under Part II,
Item 8:
Page No(s).
in this Report
Statements of Income for the years ended
September 30, 1998, 1997 and 1996 17
Balance Sheets at September 30, 1998 and 1997 18
Statements of Capitalization at September 30, 1998 and 1997 19
Statements of Retained Earnings for the years
ended September 30, 1998, 1997 and 1996 20
Statements of Cash Flows for the years ended
September 30, 1998, 1997 and 1996 21
Notes to Financial Statements 22-31
Report of Independent Public Accountants 32
Supplementary Financial Information 33
(2) Financial Statement Schedules
The following supplementary financial statement schedules required by
Rule 5-04 of Regulation S-X, and report thereon, are filed as part of this
Form 10-K on the page indicated below:
Schedule Page No. in
Number Description this Report
II Valuation and Qualifying Accounts for the three years
ended September 30, 1998 36
Report of Independent Public Accountants 32
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.
<PAGE>
(3) Exhibits Required by Item 601 of Regulation S-K
See Exhibit Index on pages 38 and 39.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed during the quarter ended
September 30, 1998.
(c) Exhibits - See Exhibit Index on pages 38 and 39.
(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 Charged to Balance
Year ended beginning costs and other at end
September 30, Description of period expenses accounts(1) Deductions of period
- -----------------------------------------------------------------------------------------------
<C> <S> <S> <S> <S> <S> <S>
1998 Allowance for
doubtful accounts $1,309 $1,080 $118 $1,419 $1,088
1997 Allowance for
doubtful accounts 1,176 1,190 136 1,193 1,309
1996 Allowance for
doubtful accounts 907 1,130 138 999 1,176
_____________________
(1) Represents recoveries on accounts previously written off
</TABLE>
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
ENERGYNORTH NATURAL GAS, INC.
Date: December 22, 1998 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 22, 1998.
/s/ Robert R. Giordano Director and Chief Executive Officer
Robert R. Giordano (principal executive officer)
/s/ Michelle L. Chicoine Director and President
Michelle L. Chicoine
/s/ Kenneth M. Margossian Director and Executive Vice President
Kenneth M. Margossian
/s/ Frank L. Childs Director and Senior Vice President,
Frank L. Childs Treasurer and Chief Financial Officer
(principal financial officer)
/s/ David A. Skrzysowski Vice President & Controller
David A. Skrzysowski (principal accounting officer)
/s/ Edward T. Borer Director
Edward T. Borer
/s/ N. George Mattaini Director
N. George Mattaini
<PAGE>
EXHIBIT INDEX
The exhibits listed below are filed herewith, or are
incorporated herein by reference to other filings.
Exhibit
Number Description
3.1 Articles of Incorporation of EnergyNorth 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
<PAGE>
reference to Exhibit 10.1 to EnergyNorth, Inc.'s Form
10-K (File No. 0-11035) for the fiscal year ended
September 30, 1993.
10.2 Gas transportation agreement (Contract No. 632),
dated as of September 1, 1993, between Tennessee
Gas Pipeline Company and EnergyNorth Natural Gas, Inc.
is incorporated by reference to Exhibit 10.2 of
EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the
fiscal year ended September 30, 1995.
10.3 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.
10.4 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, 1998
and condensed statement of income and statement of cash flows for the fiscal
year ended September 30, 1998 and is qualified in its entirety by reference to
such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 107,255<F1>
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 19,036
<TOTAL-DEFERRED-CHARGES> 10,484
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 136,775
<COMMON> 3,000
<CAPITAL-SURPLUS-PAID-IN> 22,538
<RETAINED-EARNINGS> 19,265
<TOTAL-COMMON-STOCKHOLDERS-EQ> 44,803
0
0
<LONG-TERM-DEBT-NET> 42,432
<SHORT-TERM-NOTES> 1,891
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 450
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 47,199
<TOT-CAPITALIZATION-AND-LIAB> 136,775
<GROSS-OPERATING-REVENUE> 85,296
<INCOME-TAX-EXPENSE> 2,812
<OTHER-OPERATING-EXPENSES> 74,257
<TOTAL-OPERATING-EXPENSES> 77,069
<OPERATING-INCOME-LOSS> 8,227
<OTHER-INCOME-NET> 1,111
<INCOME-BEFORE-INTEREST-EXPEN> 9,338
<TOTAL-INTEREST-EXPENSE> 4,425
<NET-INCOME> 4,913
0
<EARNINGS-AVAILABLE-FOR-COMM> 4,913
<COMMON-STOCK-DIVIDENDS> 3,803
<TOTAL-INTEREST-ON-BONDS> 3,628
<CASH-FLOW-OPERATIONS> 13,646
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0
<FN>
<F1>Net of accumulated depreciation of $51,309
</FN>
</TABLE>
